WO2009070667A1 - Methods of identifying fluids using terahertz irradiation - Google Patents

Abstract

The present invention relates to systems and methods for sensing and identifying the characteristics of a hydrocarbon fluid steam in fluid conduits such as pipelines in both sub-surface and surface environments. In one embodiment, the invention relates to methods for sensing, monitoring and identifying certain contaminants occurring in the stream of produced hydrocarbons using terahertz time-domain spectroscopy (THz-TDS) techniques. In various configurations, the assembly senses the presence and/or concentrations of water, viscosity values, the presence of a gas, the gas/oil ratio (GOR), the API gravity of the fluid within the conduit, and impurities and contaminants such as solid asphaltenic deposits.

Description

METHODS OF IDENTIFYING FLUIDS USING TERAHERTZ IRRADIATION

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims priority to U.S. Application Serial No. 60/991,471, filed on November 30, 2007, which is incorporated herein in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0002] Not applicable. REFERENCE TO APPENDIX [0003] Not applicable. FIELD OF THE INVENTION.

[0004] This disclosure relates to methods, systems, and apparatus for monitoring parameters of fluids flowing within a conduit. More specifically, this disclosure relates to methods of monitoring a parameter of interest in a fluid flowing within a conduit, systems and assemblies for monitoring a parameter of interest of a fluid flowing within a conduit, and methods for producing a hydrocarbon from a subterranean formation or reservoir while the monitoring properties of the fluids, in which the monitoring is carried out using terahertz radiation.

BACKGROUND OF THE INVENTION

[0005] Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing portion of the formation. Once a wellbore has been drilled, the well must be completed before hydrocarbons can be produced from the well. A well completion involves the design, selection, and installation of equipment and materials in or around the wellbore for conveying, pumping, and/or controlling the production or injection of fluids. After the well has been completed, production of oil and gas can begin. [0006] In both the construction and use of hydrocarbon production fluid flow lines, as well as processing and transportation facilities, it is often desirable to know whether corrosive materials or other contaminants are contained within the formation fluids that are traveling within the flow lines in order to select the appropriate materials for the design and construction of the pipelines and related facilities. In particular, it may be necessary to know the concentration of any hydrogen sulfide contained within the formation fluids if the proper materials are to be used. Additionally, it is desirable to identify and monitor certain contaminants within production fluid lines as early as possible, as their presence can affect the producibility, metering, separation, processing, transportation, and/or sales price of the hydrocarbon production stream. In addition, several of these contaminants, such as hydrogen sulfide, may raise safety or environmental issues.

[0007] The desirability of taking fluid samples from hydrocarbon production fluid-flow lines for chemical and physical analysis of the fluids during downstream operations has long been recognized by production companies, and such sampling has been performed by several companies for many years. Samples of produced fluid are typically collected as early as possible in the life of a reservoir for analysis at the surface and, more particularly, in specialized laboratories. The information that such analysis provides is vital in the planning and development of production of fluids from subterranean hydrocarbon reservoirs, as well as in the assessment of downstream production line capacity and performance. Examples of production fluid characteristics that are of particular importance to hydrocarbon well operators include, for example, the presence and/or percentage of water, the presence of gas (e.g., methane), the Gas:Oil ratio (GOR), the condensate gas ratio (CGR), the aliphatic/aromatic hydrocarbon ratio, asphaltene formation and presence, and the presence of corrosive or poisonous chemicals, such as hydrogen sulfide (H2S). Hydrogen sulfide detection is especially important for early detection, due to the fact that if H2S is present in a production fluid flow line, there may be a higher concentration of H2S in the reservoir fluid, which can be an issue for both personnel safety and material selection during processing.

[0008] A number of approaches have been described for determining the Gas-to-Oil Ratio (GOR) including WO/2004/083833, which reportedly uses two wavelengths that are both near a single spectral peak for methane (i. e., two regions of the same methane peak) for making GOR determinations. That invention reportedly bases its spectral GOR equations on synthetic mixtures of methane and dead crude oils, and uses stock tank crude oils to represent downhole crude oil in the modeling for GOR or weight percent methane. A related patent to Mullins (U.S. Patent No. 6,476,384) describes a method for determining GOR based on two wavelengths, the first located near a methane-gas spectral peak and the second located near a liquid-hydrocarbon spectral peak (representing oil). This method reports to base its spectral GOR determination equations on a training set of binary mixtures of n-heptane (representing oil) rather than stock tank crude oils and methane. [0009] Asphaltenes are another class of contaminants within hydrocarbon production lines that can be problematic, especially if not detected and addressed early on. Asphaltenes are commonly defined as that portion of crude oil which is insoluble in heptane, are soluble in toluene, and typically exist in the form of colloidal dispersions stabilized by other components in the crude oil. Asphaltenes are often brown to black amorphous solids with complex structures, involving carbon, hydrogen, nitrogen, and sulfur. Asphaltenes are typically the most polar fraction of crude oil, and will often precipitate out upon pressure, temperature, and compositional changes in the oil resulting from blending or other mechanical or physicochemical processing. Asphaltene precipitation can occur in pipelines, separators, and other equipment, as well as downhole and in the subterranean hydrocarbon-bearing formation itself. Once deposited, these asphaltenes generally present numerous problems for crude oil producers, such as plugging downhole tubulars, choking off pipes, and interfering with the functioning of separator equipment, all of which compound the production costs and require the need for remediation. [0010] Current methods for analyzing and monitoring the compositions of fluid flow through both downhole tubulars and production pipelines outside of the wellbore itself typically require the time-consuming and often costly manual isolation of a fluid sample from the pipeline with subsequent analysis in a lab (or at the well site) in order to determine the composition of the fluid. Various techniques have also been developed to detect contaminants within production fluid flow lines, such as the presence of hydrogen sulfide. These techniques include gas chromatography applications, potentiometrics, cathode stripping applications, electrochemical hydrogen patch probes, spectrophotometry, fluorescent reagent applications, biosensors, and chemical sensors, to list a few. A review of methods of field monitoring oil-based drilling fluids for contaminants, such as hydrogen sulfide and water intrusions, has been presented by Garrett, et al. [SPE Paper 12120-PA, pp. 296-302].

[0011] For example, U.S. Patent No. 5,859,430 describes an analyzer that includes an optical fluid analyzer (OFA) and a gas analysis module (GAM). The OFA determines when fluid flowing into the tool has become substantially only gas. The gas is then diverted to the GAM, which includes a near infrared ray light source, at least one photo-detector, a gas sample cell (or cells) having portions with different path lengths, each portion having an optical window, and fiber optics which direct light in first paths from the source to the sample cell, and from the sample cell to the photo-detectors. Analysis of the different hydrocarbon gas components of the gas stream is conducted by analysis of selected CH vibrational peaks in the 5700 cm^"1 to 6100 cm^"1 range.

[0012] Several methods have also been described for determining both when and how much asphaltene will flocculate out of solution and form deposits at a given time within a production line or in the production process flow stream, under selected operating conditions, all with various degrees of accuracy and difficulty. Such methods have included electrical conductivity, light transmission, gravimetric analysis, and interfacial tension measurements. A new technique for the determination and location of the onset of asphaltene flocculation in hydrocarbon production lines using viscometric measurements of hydrocarbons, based on the colloidal nature of asphaltenes in crude oils [Escobedo, J., et al., SPE Paper No. 28018-PA; pp. 115-118 (1995)].

[0013] Many of the above-described methods of fluid analysis involve isolating a sample of a fluid, and subsequently analyzing it. This can be problematic in the case of hydrogen sulfide detection, because many of the metals and materials comprising these sampling tools react with any hydrogen sulfide in the fluid sample. Because of this reaction, when a fluid sample is subsequently analyzed for contaminants, the measured concentration of the H₂S in the sample will be lower than the actual concentration of H₂S in the fluid from the producing reservoir, giving a false indication of the levels of H₂S in the reservoir fluid. Additionally, production lines that are located in remote regions, such as in sub-sea environments like the Gulf of Mexico, are often difficult and/or costly to sample, if they can be sampled at all. Other techniques and apparatus for detecting contaminants in reservoir fluid flow lines are often limited by their ability to detect or monitor only one or two selected characteristics, or detect only selected contaminants. Therefore, there is a need for improved methods for monitoring reservoir fluid flow as it is produced, in real time, that can simultaneously monitor several characteristics and a number of contaminants, as well as apparatus for making such measurements and methods of interpreting the measurements to obtain as much information about the fluid with the use of fewer tools.

BRIEF SUMMARY OF THE INVENTION

[0014] This application for patent discloses flow monitors that can measure characteristics of, and detect contaminants in, fluids flowing through fluid flow conduits, as well as methods and systems for use in such measurement and detection, using terahertz time- delay spectroscopy (THz-TDS). In general, methods for the measurement, characterization, identification, and monitoring of components within hydrocarbon- containing fluids are described.

[0015] In accordance with one aspect of the present disclosure, methods of identifying a fluid are described, wherein the method comprises generating a terahertz wave pulse, propagating the terahertz wave pulse through a fluid, detecting the terahertz wave pulse after it propagates through the fluid over a path having a predetermined path length, determining a time of flight (tof) of the terahertz wave pulse through the fluid, determining a absorption coefficient and/or refractive index from the determined time of flight, and identifying the fluid based on the absorption coefficient, the refractive index, or both. [0016] In a further aspect of the present disclosure, methods of identifying one or more characteristics of a fluid are described, wherein the methods comprise generating a terahertz wave pulse, propagating the terahertz wave pulse through a fluid, detecting the terahertz wave pulse after it propagates through the fluid over a path having a predetermined path length, determining a time of flight (tof) of the terahertz wave pulse through the fluid, determining a absorption coefficient and/or refractive index from the determined time of flight, and identifying the fluid based on the absorption coefficient α(ω), the refractive index η(ω), or both.

[0017] In a further aspect of the present disclosure, methods of producing hydrocarbon material from a subterranean formation are described, the methods comprising providing a wellbore extending through at least a portion of the subterranean formation, providing a conduit in fluid communication with a hydrocarbon producing zone within the subterranean formation, producing a hydrocarbon fluid material from the producing zone, and measuring a parameter in the fluid material during production using a terahertz spectrometer, wherein the parameter measured comprises fluid viscosity, fluid water content, concentration, dielectric constant, the API gravity of the fluid, the gas-to-oil ratio (GOR) of the fluid, asphaltene content, and combinations thereof. [0018] In another aspect of the present disclosure, methods for characterizing and monitoring the level of contaminant components in hydrocarbon production lines for flow metering and reservoir surveillance purposes are described.

[0019] In a further aspect of the present disclosure, methods for analyzing hydrocarbon- containing fluids using terahertz time-domain spectroscopy are described. [0020] In yet another aspect of the present disclosure, methods for the monitoring and measurement of water content in hydrocarbon-containing fluid flow lines, such as production lines in fluid communication with a hydrocarbon-containing reservoir or in a process flow stream, using terahertz time-domain spectroscopy are described. [0021] In a further aspect of the present disclosure, methods for the monitoring and measurement of the viscosity of hydrocarbon-containing fluids using terahertz time- domain spectroscopy are described.

[0022] In another aspect of the present disclosure, methods for the monitoring and measurement of asphaltene content and concentration in hydrocarbon-containing fluids using terahertz time-domain spectroscopy are described.

[0023] In yet another aspect of the present disclosure, methods for detecting asphaltene deposits and asphaltene precipitation within conduits which transport hydrocarbon- containing fluids are described.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS [0024] The following figures form part of the present specification and are included to further demonstrate certain aspects of the present invention. The invention may be better understood by reference to one or more of these figures in combination with the detailed description of specific embodiments presented herein.

[0025] FIG. 1 is a schematic diagram of a fluid monitoring system according to some embodiments of the invention.

[0026] FIG. 2 is a schematic diagram of a terahertz wave spectrometer assembly according to certain aspects of the present disclosure.

[0027] FIG. 3 illustrates an exemplary terahertz fluid characterization system for use in accordance with the present disclosure.

[0028] FIG. 4 is a side-view of an exemplary sample measurement container in association with the present disclosure.

[0029] FIG. 5 is a front view of the container of FIG. 2.

[0030] FIG. 6 illustrates THz-TDS measurements of hexane samples at varied path lengths.

[0031] FIG. 7 illustrates refractive index measurements of hydrocarbon samples measured using THz-TDS.

[0032] FIG. 8 illustrates the absorption coefficient of hydrocarbon samples measured using THz-TDS.

[0033] FIG. 9 illustrates the repeatability of refractive index characterizations over time. [0034] FIG. 10 illustrates the repeatability of refractive index characterizations over time. [0035] FIG. Il l illustrates refractive index measurements of mixed hydrocarbon samples and reservoir samples.

[0036] FIG. 12 illustrates absorption coefficient measurements of hydrocarbon samples and reservoir samples.

[0037] FIG. 13 illustrates the effect of water content on absorption coefficient measurements of a reservoir sample.

[0038] FIG. 14 illustrates a comparison of refractive index versus viscosity for selected linear alkanes.

[0039] FIG. 15 illustrates exemplary waveforms for hydrocarbon samples obtained through a fixed path length.

[0040] While the inventions disclosed herein are susceptible to various modifications and alternative forms, only a few specific embodiments have been shown by way of example in the drawings and are described in detail below. The figures and detailed descriptions of these specific embodiments are not intended to limit the breadth or scope of the inventive concepts or the appended claims in any manner. Rather, the figures and detailed written descriptions are provided to illustrate the inventive concepts to a person of ordinary skill in the art and to enable such person to make and use the inventive concepts. DETAILED DESCRIPTION

[0041] One or more illustrative embodiments incorporating the invention disclosed herein are presented below. Not all features of an actual implementation are described or shown in this application for the sake of clarity. It is understood that in the development of an actual embodiment incorporating the present invention, numerous implementation-specific decisions must be made to achieve the developer's goals, such as compliance with system- related, business-related, government-related and other constraints, which vary by implementation and from time to time. While a developer's efforts might be complex and time-consuming, such efforts would be, nevertheless, a routine undertaking for those of ordinary skill the art having benefit of this disclosure.

[0042] In general terms, Applicants have created methods and systems for characterizing fluids, in particular fluids within conduits such as hydrocarbon recovery tubulars and process flow-lines.

[0043] Turning now to the figures, FIG. 1 is a schematic diagram of one embodiment of a monitoring assembly 20 in accordance with the present invention, wherein the assembly 20 can be associated with a fluid conduit 10 as appropriate. As used herein, the term "associated with a fluid conduit" is meant to contemplate that the assembly 20 can be coupled exterior to, on the interior of, proximate to, or remote to a fluid conduit, 20. As used herein, the term "fluid conduit" means a closed conduit, such as a pipeline or other substantially tubular member, an open conduit such as an aqueduct, or combinations thereof, for use in transporting liquids, gases, slurries, and other fluids. Such fluids, in accordance with the present invention, typically include hydrocarbons and fluids containing hydrocarbons, and optionally fluid containing hydrocarbons and their associated contaminants such as water, polar molecules, asphaltenes, and the like. The assembly includes a chamber 24 within a housing 22, containing a terahertz analysis measurement system 30. Monitoring assembly 20 can also contain a transmitter 26 for sending signals from the monitoring assembly 20 to a receiver, which can be located on or in the chamber 24. In some aspects, the transmitter 26 can be in electrical communication with the terahertz analysis measurement system 30 and/or external sensors (not shown). [0044] The transmitter 26 receives signals from the terahertz analysis measurement system 30 and/or the external sensors (not shown) and sends them directly to a receiver on or near the surface. In some embodiments, a processor 29 is in electrical communication with at least the transmitter 26. In general terms, the processor 29 receives signals from the terahertz analysis measurement system 30 and/or the external sensors, processes the signals into a conditioned signal, and sends the conditioned signal to the transmitter 26. The transmitter 26 then sends the conditioned signal to a remote receiver on or near the surface. The processor 29 can be located on the housing 22, or in the chamber 24. [0045] In one embodiment, the transmitter 26 continuously sends a signal to the receiver, for example, a signal corresponding to real-time measurements of the water content, the oil/gas ratio, or the hydrogen sulfide content of a hydrocarbon fluid within a fluid conduit as obtained by measurement system 30. In other embodiments, the transmitter 26 only sends a signal to the receiver when a certain event occurs, for example, once the water content or oil/gas ratio reaches a certain level. In still other embodiments, the transmitter 26 sends a signal to the receiver at predetermined intervals.

[0046] The monitoring assembly 20 can also contain a receiver 28 for receiving signals from an operator at the surface. The receiver 28, which may also be disposed within or outside of the chamber 24, can be in electrical communication with any or all of the terahertz analysis measurement system 30, the transmitter 26, and the processor 29. The receiver 28 can receive a signal from the operator and pass the signal to another component, causing an action within the monitoring assembly 20. For example, the receiver 28 may receive a signal to turn on or to turn off a the terahertz analysis measurement system 30. Thus, the receiver 28 can enable an operator at the surface to remotely control one or more functions of the monitoring assembly 20. [0047] Signals can be sent to and from the monitoring assembly 20 using any methods known in the art. For example, if the conduit is underground, the monitoring assembly 20 can be linked to a receiver and/or transmitter on or near the surface via one or more cables. The cables can be disposed inside of the conduit, outside of the conduit, or within a wall of the conduit. Alternatively, the monitoring assembly 20 can communicate with the surface using a wireless communication system. Suitable wireless communication methods include, for example, mud-pulse telemetry, acoustic, and electromagnetic techniques. It should be understood that any communication technique, wireless or not, may be used to facilitate signal transfer between the monitoring assembly 20 and a receiver at or near the surface, or remote from the assembly 20. Examples of suitable communication systems are known in the art.

[0048] Power for operating the various electronic components of the monitoring assembly 20 can be supplied, for example, by a power source, such as a battery, located in or near the chamber 24, a turbine powered by fluid flowing within the fluid conduit, or other suitable powering means known in the art.

[0049] The various components of the monitoring assemblies 20 described herein can be manufactured from any material that can withstand prolonged exposure to the environment in which the assembly will be placed. Suitable materials include polymers and metals. Polymeric materials can be used alone or in combination, either with or without reinforcement. Suitable polymeric materials include but are not limited to polyurethanes, such as a thermoplastic polyurethane (TPU), TEFLON® (Polytetrafluoroethylene), ethyl vinyl acetate (EVA), thermoplastic polyether block amides, thermoplastic olefin, silicones, poly ethylenes, polyimides, acetal, and equivalent materials. Reinforcement, if used, may be by inclusion of glass or carbon graphite fibers or para-aramid fibers, such as the KEVLAR™ brand sold by DuPont, or other similar method. Suitable metals include but are not limited to steel, stainless steel, and aluminum, for example. Also, both polymeric and metallic materials can be used to fabricate the components of the monitoring assemblies 20. Other suitable materials will be apparent to those skilled in the art. [0050] FIG. 2 illustrates the general structure of a terahertz analysis measurement system 30 such as a terahertz time-domain (THz-TDS) wave spectrometer system, according to on embodiments of the present invention. The terahertz wave spectrometer system shown therein is part of a monitoring assembly 20, comprising a terahertz generating assembly 21a and a terahertz detecting assembly 21b. Assemblies 21a and 21b comprise a predetermined, pulsed light source 32 capable of producing a femtosecond pulse train light path 31, a group velocity dispersion compensation and optical fiber coupling assembly 34, a control box with an optical delay device 36, a terahertz wave generator 38, and a terahertz wave detector 44, as well as fiber optic cables 37a and 37b. System 30 can also optionally include a spectroscopic processor (not shown), or other appropriate hardware capable of processing the frequency domain information obtained as will be described herein by taking the Fourier-Transform of the waveform measured in the time domain, using a computer or other suitable Human- Machine Interaction (HMI) device. The light from the optical delay device 36 is guided by and travels through two (or more) fiber optic cables 37a and 37b, which serve to provide optical communication between assemblies 21a and assemblies 21b. The terahertz wave generator 38 is for generating a terahertz wave by using the excitation light guided by the optical delay device 36. The terahertz wave detector 44 is for detecting the terahertz wave that has passed through the fluid flow stream A and that is guided by the terahertz wave light path 41a, thereby outputting a terahertz wave detection signal. The spectroscopic processor 29 is for processing the detection signal from the terahertz wave detector 44, as necessary.

[0051] As an example of the pulse light source 32, a pulse laser device, such as a femtosecond (fs) pulse laser, can be used. Suitable pulse light sources 32 can include SiGe/Si lasers, Ti/sapphire lasers, and Femtolite ultrafast fiber lasers based on doped (e.g., Erbium- doped or Yb-doped) fiber oscillators, such as are available from IMRA (Institut Minora de Recherche Avancee) America, Inc. (Ann Arbor, MI). Preferably, the pulse light source 32 is a fiber-coupled femtosecond laser system, or a femtosecond laser system capable of being directly coupled to optical fiber(s), as these systems directly couple the pulse to the optical fibers (37a, 37b) and are compact in size. In accordance with aspects of this embodiment of the present invention, the pulse laser systems can generate an excitation light pulse having a pulse width less than about 1 picosecond (ps; one trillionth (10-12) of a second), preferably in the range from about 10 femtoseconds (fs; one millionth of a nanosecond, or 10-15 of a second) to about 900 femtoseconds, more preferably in the range from about 10 fs to about 500 fs, and more preferably in the range from about 10 fs to about 300 fs, including about 20 fs, about 30 fs, about 40 fs, about 50 fs, about 60 fs, about 70 fs, about 80 fs, about 90 fs, about 100 fs, about 120 fs, about 140 fs, about 160 fs, about 180 fs, about 200 fs, about 225 fs, about 250 fs, about 275 fs and about 300 fs, as well as values falling within ranges of these pulse width ranges, e.g. from about 95 fs to about 115 fs. Accordingly, the pulse laser systems in accordance with the present invention can produce excitation light pulses having a pulse energy ranging from about 1 mJ to about 100 mJ or more, as appropriate. The excitation-light optical system also includes an optical delay device 36, coupled to the pulse light source 32 via fiber-optic cables. Optical delay device 36 can be any suitable such device known in the art, such as the terahertz control devices available from Picometrix (Ann Arbor, MI), and can be as simple as a mirror mounted on a translation stage. Such control devices can optionally include additional mirrors and other appropriate assemblies necessary to control the relative pulse propagation path length between the transmitter and the receiver, including a fiber splitter or beam splitter for use before the femtosecond light pulse train proceeds towards the terahertz wave generator 38. Suitable fiber-coupled transmitters/terahertz wave generators 38 for use with the present invention can be obtained from Picometrix (Ann Arbor, MI). [0052] Returning to FIG. 2, an output lens 39 is provided in the terahertz wave optical path 41a at one side of the optical switch 38a, where the terahertz wave is generated. Typically, the output lens 39 (and input lens 43, described below), are chosen to be of a material such that its index of refraction (n) does not differ too substantially (e.g., by more than about 0.5) from the material of the substrate, nor does it absorb as much as the material of the substrate. For example, when the substrate 94 is GaAs, the lens 39 is typically silicon or a silicon-like material, because its index of refraction (nSi=3.4) does not differ appreciably from that of the GaAs substrate (nGaAs=3.6). Additionally, in this example, using a material like silicon that has a similar index of refraction reduces Fresnel reflections between the lens and the substrate. In accordance with certain aspects of the present disclosure, silicon or TEFLON™ is the preferably material for use as the lens 40 over GaAs because, while a GaAs lens can substantially match the refractive index, GaAs absorbs terahertz radiation more than silicon, making GaAs less preferable. The terahertz waves generated in accordance with the present invention can range from about 0.01 THz to about 30 THz, more preferably from about 0.1 THz to about 10 THz, or, alternatively and equally equivalent, from about 50 GHz to about 30 THz. [0053] While not described herein, one or more mirrors (which can be of metal or any other suitable, highly-reflective material, such as gold or aluminum) may also be provided in the terahertz wave optical path 41a, in accordance with aspects of the present invention. The mirrors can be used for converting the terahertz wave, which has been generated by the terahertz wave generator 38 and which has passed through the output lens 40, into substantially a parallel, collimated light, as necessary. Optionally, or in addition to functioning to collimate the terahertz radiation, mirrors can be included within the present assemblies in order to guide the terahertz pulses. Such mirrors can be any suitable mirror known in the art, including paraboloid mirrors, such as an on-axis or off-axis paraboloidal mirror. Further, one or more additional pairs of lens can be used in system 30 in order to focus the beam down to a smaller, or desired, spot size.

[0054] With continued reference to the general illustration of terahertz time-domain spectroscopy of FIG. 2, having passed through lens 40, the terahertz wave optical path 41 continues towards the exterior of conduit 10. As further shown in the Figure, and in accordance with aspects of the present disclosure, when conduit 10 is made of a material substantially non-transparent to terahertz waves, in order to monitor the fluid stream within the conduit, the conduit necessarily further comprises windows 11a and l ib (or other suitable, THz-transparent elements) in the fluid conduit itself which are substantially parallel to each other. Windows 11a and lib are preferably comprised of a material that is transparent to terahertz waves, such as fiberglass or plastic PEEK (PolyEtherEtherKetone). In other aspects of the present invention, an element of the fluid conduit itself is transparent to terahertz waves, so as to allow for the attachment of several monitoring assemblies 20. In accordance with this aspect, the fluid conduit, which is typically metal or some other appropriate material, is coupled to a terahertz-transparent pipe element intermediate two portions of fluid conduit, via metal-to-plastic couplings or other appropriate coupling means known in the art, including threads, tapered threads, and transition fittings. Suitable materials for the terahertz-transparent pipe element include THz-transparent plastics such as PEEK and fiberglass, such as those available from Star Fiber Glass Systems (San Antonio, TX).

[0055] Having passed through first window 1 Ia in conduit 10, the terahertz wave then passes through fluid stream A, such as a hydrocarbon stream, which in some embodiments may substantially perpendicular to the terahertz wave optical path 41a. The fluid stream A is a target whose characteristics are desired to be measured by the spectrometer. Examples of the fluid stream A in accordance with the present invention can include a gas, a liquid, or a combination of two or more gases or liquids, suitable liquids including water, hydrocarbons, asphaltenes, and the like, discussed in more detail below. [0056] On the opposite side of transparent window 1 Ib, an input lens 42 is provided in the terahertz wave optical path 41a. The input lens 42 is for focusing the terahertz wave 41a, which has passed through the fluid stream A, onto an optical switching device 44a via input lens 43. The optical switching device 44a constitutes the terahertz wave detector 44, such as from Picometrix (Ann Arbor, MI). The input lens 43, similar to output lens 39, can be from silicon lenses, for example, as well as other suitable materials known in the art. [0057] While not illustrated herein, the terahertz generating system described herein can optionally be provided with a variable optical delay translation stage. Such variable optical delay translation stages are for setting (adjusting) the difference between the timing of the probe light and the timing of the excitation light. The optional variable optical delay translation stage can be any suitable translation stage, such as the VP-25X translation stage or UlLTRAlign™ series translation stage available from Newport (Irving, CA). Typically, translation stages include a movable drive, which can be motorized or manual, and can be linear or vertical. Suitable translation stages for use herein can also include a ball-screw drive, as appropriate, and, optionally an optical delay controller for driving the translation stage and to control its position. By driving (controlling) the position of the translation stage along a predetermined distance, the optical delay controller 36 can perform control operations to change and set the length of the optical path of the probe light, thereby changing and setting the difference between the excitation light irradiation timing (terahertz wave generating timing) and the terahertz irradiation timing (terahertz wave detecting timing). Typically, translation stages can move distances ranging from about 1 mm to about 4 inches, depending upon the application and the size of the translation stage itself.

[0058] Alternatively, The terahertz generating and detecting system described herein may be mounted on an optical delay system capable of varying the optical path length of the terahertz wave path from the terahertz wave generator to the terahertz wave detector. An advantage of varying the terahertz path length instead of the optical path length of one of the optical excitation pulses, is that it does not require the optical excitation pulses to be coupled out and back into the fiber optical system. Instead, the path length of the terahertz wave path is varied, which terahertz waves are not confined in a fiber anyway. This facilitates the incorporation of the terahertz spectroscopy system in a downhole tool, which is expected to be exposed to extreme conditions involving heavy vibration and extreme temperature and pressure variations. By varying the terahertz optical path length, the arrival time of the terahertz wave relative to the arrival time of the optical excitation pulse at the terahertz wave detector 44 is varied.

[0059] Additional objective lenses 40 and 42 can be further provided in the system 30 described herein, as necessary. Objective lens 40 and 42 can be of any appropriate shape, such as hemispherical, extended hemispherical, collimating, or hyperhemispherical, and can be of any appropriate lens material, including glass, plastic (e.g., polymers), silicon, quartz, CaF2, ZnSe, Ge, combinations thereof, and the like.

[0060] Again referring to FIG. 2, as illustrated therein, the system can also comprise a control unit 59, which can be housed at an appropriate location within assembly 20, or can be housed remotely in control housing station with or in conjunction to a control unit for controlling and operating monitoring assembly 20. According to aspects of the present embodiments, the control unit can contain a spectroscopic processor which can include one or more of the following optional components, as necessary or desired: a current-to-voltage conversion amplifier, such as a transimpedance amplifier, and an analyzing device. Control unit 59 can also control the optical delay line, as necessary. [0061] Turning to FIG. 3, the setup of an exemplary THz fluid characterization system 80 for use with aspects of the present disclosure is generally illustrated. The THz-TDS system 80 can be used to generate and detect THz electromagnetic pulses for sample analysis. It differs from the system in FIG. 2 in that the laser system 82 propagates in free-space and no fiber is used. This is due to the availability of equipment, not because of any limitation of fiber. The THz-TDS system 80 contains a femtosecond laser system 82 to generate pulses on the order of 100 fs of duration at a repetition rate on the order of about 80 MHz. The laser pulse is guided by mirrors to a beam splitter 83, which then directs part of the beam to the THz transmitter 88 and the other part to an optical delay 84 and then to the THz receiver, 86. When the laser pulse reaches the THz transmitter 88, a T-ray is generated and is propagated through the sample, which is contained within sample container 90, having a bellows-portion 92 which allows for the measurement of the sample(s) at several, variable path lengths, as will be described in more detail below. When the laser pulse reaches the THz receiver 86, the electric field of the T-ray that has propagated through the sample is measured. The optical delay line 84 varies the laser pulse arrival time at the THz receiver 86 relative to the laser pulse arrival time at the THz transmitter 88. This allows the electric field of the THz pulse to be sampled in the time- domain, as described above in connection with FIG. 2.

[0062] Alternatively, in accordance with further aspects of the present invention, while disclosed in the context of a monitoring assembly for use in a local or remote laboratory, the assemblies and methods of monitoring and characterizing hydrocarbon constitutents in fluid flow lines may be applied directly in downhole operations, such as a part of a wireline tool, alone or in combination with an OFA, infrared (near-, far, or visible) spectrograph, NMR, or the like. Additionally, the monitoring assemblies such as 20 and 100 (see below) described herein can be disposed, for example, on the inside surface of a round or curved fluid conduit, such as described, for example, in commonly owed Application PCT/US2007/069970, which is incorporated herein by reference in its entirety. [0063] As used herein, the term "hydrocarbon" refers broadly to heavy oils, light oils, oil- based mud, and mixtures thereof. Hydrocarbons which may be discerned and characterized using the terahertz time-domain methods of the present disclosure include but are not limited to hydrocarbons which are selected from the group consisting of straight chain, branched chain, or cyclic alkanes, alkenes, and alkynes, including cycloalkanes, aromatic hydrocarbons, and mixtures thereof, which may occur as solids, liquids, or gases. Further, the term hydrocarbon is meant to refer to those organic compounds (both saturated and unsaturated) composed solely of the elements hydrogen and carbon, as well as those also comprising one or more heteroatoms (e.g., nitrogen, sulfur, and/or oxygen), although preferably the hydrocarbons which may be monitored and characterized according to the present disclosure comprise only carbon and hydrogen. Exemplary hydrocarbons which may be monitored and characterized according to the methods described herein include but are not limited to alkanes of the general formula CnH2n+2 (wherein 'n' is an integer greater than or equal to 1), such as methane, ethane, propane, hexane, n-octane, decane, and the like, as well as mixtures of alkanes; alkenes of the general formula CnH2n (wherein 'n' is an integer greater than or equal to 1), including 1-butene and 1-propene, and mixtures of alkenes; alkynes of the general formula C_nH_2n^ (wherein 'n' is an integer greater than or equal to 1), and mixtures of alkynes; cycloalkanes of the general formula C_nH_2n (wherein 'n' is an integer greater than or equal to 1), including cyclohexane and other "naphthenes", as well as mixtures thereof; aromatic compounds of the general formula C_nH2_n_₆, including both monocyclic (benzene) and polycyclic (napthene) aromatics; as well as mixtures of the above described hydrocarbons. [0064] Similarly, as used herein, the term asphaltenes refers generally to those heavy, polar fractions found in crude oil or hydrocarbons, and which can vary in complexity and can consist of associated systems of polyaromatic sheets bearing alkyl side chains, as well as the heteroatoms O, N and S and the metals V, Ni and Fe. More generally, from a chemical standpoint, as used herein the term "asphaltenes" refers to those fractions of oil or hydrocarbon mixtures that are insoluble in n-heptane or n-pentane (or other n-paraffins) and are soluble in aromatic solvents such as benzene or toluene [Cimino, R., et al., Ch. 3 in "Asphaltenes: Fundamentals and Applications", Sheu, E. Y. and Mullins, O. C. (Eds.), Plenum Press, N. Y., pp. 97-130 (1995)]; Sharma, M.K. and Yen, F.T. (Ed.), "Asphaltene Particles in Fossil Fuel Exploration, Recovery, Refining and Production Processes," Plenum Press, NY (1994)].

[0065] Further, the methods described herein may also be used to determine the gas-to-oil ratio (GOR), viscosity, and API gravity of fluids flowing through a conduit, based on the acquisition of α(ω) and η(ω) measurements using THz-TDS at multiple path lengths and extracting the requisite information therefrom using one or more mathematical enumerations. As used herein, the term "API gravity" refers to a specific gravity scale developed by the American Petroleum Institute (API) for measuring the relative density of various petroleum liquids, expressed in degrees, so as to describe the "lightness" or "heaviness" of crude oil and the like. API gravity is typically gradated in degrees on a hydrometer instrument and was designed so that most values would fall between 10° and 70° API gravity. The arbitrary formula used to obtain this effect is: API gravity = (141.5/SG at 60 ⁰F) - 131.5, where "SG" is the specific gravity of the fluid. According to the API gravity scale, light crude oil is defined as having an API gravity higher than 31.1 ⁰API; medium crude oil is defined as having an API gravity between 22.3 ⁰API and 31.1 ⁰API; and heavy oil is defined as having an API gravity below 22.3 ⁰API. [0066] In one embodiment, the methods of the present invention can be applied to hydrocarbons in a process flow stream under real-time conditions. In this application, the terahertz signal may be applied to a hydrocarbon, such as an oil, for which an agglomerative state is to be determined before any dilution of the oil that may be involved in the processing (e.g., refining) which the hydrocarbon is to undergo and without diluting or adulterating the oil during the application of the signal. A THz-TDS system as described herein is most preferably installed on or within the reactor, vessel, exchanger, pipeline, tank or other container or conduit in which the hydrocarbon is being stored, transferred, or processed so that the signal may be applied to the hydrocarbon in the process flow stream and without removing the hydrocarbon from such process flow stream, thereby avoiding disruption of or interference with the storage, transfer or process to which the hydrocarbon is being subjected.

[0067] The term, "process flow stream", as it is used herein, means any stream or bulk amount of oil that is not a small sample and is meant to include oils in pipelines, reactors, heat exchanges, tanks, pumps, pipes, lines, or any other container or conduit in which oil is conventionally stored, handled, processed, transported, or transferred to, from or during processing or storage, but is not meant to include small samples of oil which have, for testing purposes, been removed from or separated from a bulk amount of the oil for which the agglomerative state of asphaltenes is to be measured or controlled. [0068] When it is said that a test, probe, or terahertz time-domain instrument is applied, "in-line", it means that the test, probe, or instrument of interest is applied directly in the process flow stream, rather than to a sample of such stream.

[0069] The following examples are included to demonstrate preferred and exemplary embodiments of the invention. It should be appreciated by those of skill in the art that the techniques disclosed in the examples which follow represent techniques discovered by the inventor(s) to function well in the practice of the invention, and thus can be considered to constitute preferred modes for its practice. However, those of skill in the art should, in light of the present disclosure, appreciate that many changes can be made in the specific embodiments which are disclosed and still obtain a like or similar result without departing from the scope of the invention.

EXAMPLES

Example 1 : Development of a THz Fluid Characterization System. [0070] A terahertz time-domain fluid characterization system was developed to generate and detect terahertz (THz) electromagnetic pulses for use in monitoring and characterizing samples in accordance with the present disclosure. The system described above and illustrated schematically in FIG. 3 includes a unique sample container 92, which was necessary to develop in order to characterize fluids accurately by taking terahertz measurements at several path lengths over time. The details of this container 100 will now be described in more detail. [0071] A side view of this sample container 100 is illustrated in FIG. 4. The container 100 is comprised of vertical support struts 102 and top member 104, wherein support struts 102 allow for threadable attachment to a staging table or laser/optical table 105, such as those available from Melles Griot (Carlsbad, CA). The container system further comprises a first, fixed end 110, and a second, movable end 112, and an expandable/contractable bellows system 120 intermediate between 110 and 112, wherein end 112 can be programmed to move (using any number of programs and methods known in the art) in the direction of the arrow along a translation stage 106 having a track 108 or the equivalent allowing for longitudinal movement. The ability of container 100 to move in a longitudinal direction allows for the measurement of sample characteristics at several path lengths, allowing for the path length to be changed without having to remove the sample. Attached to each of the first and second end plates 110, 112 are TEFLON® (Polytetrafluoroethylene) windows 116a, 116b which are sandwiched between grooved flanges 114 having annular grooves formed therein which allow for VITON® O-rings or the like (not shown) to be inserted and assist in forming a seal between the Teflon windows, the end faces, and the flanges 114. Flanges 114, and end plates 110, 112 can be obtained from a number of sources, such as the Kurt J. Lesker Company (Clairton, PA). The sandwich assembly comprising the end plates 110, 112, the flanges 114, and the TEFLON® windows 116 are held together by bolts or equivalent, mechanical devices. The fluid characterization system 100 also comprises a thermoplastic tubing 130 which runs through the system, contains the volume of the sample to be characterized, and which is flexible enough to expand and contract along with the bellows 120. As shown in FIG. 4, the tubing 130 is attached at its ends to the aluminum plates 114 by VITON® O-rings in order to create a tight seal.

[0072] In FIG. 5, a front view of part of the sample container 100, viewed along line x in the direction of the arrow of FIG. 4, is shown. The view illustrates the orientation of the TEFLON® window 116a, and the o-ring 115 fit into an annular groove of end plate 110. Machined holes 122 within plate 110 allow for bolts 118 to threadably sandwich the plate 110, window 116a, and flange 114 (not shown) together. [0073]

Example 2: Distinguishability of Hydrocarbons. General Experimental Details. [0074] In this example, as well as the subsequent examples detailed herein, a number of linear alkanes, and a commercially available mineral oil were used. Unless specified otherwise, all commercial products were obtained from Sigma-Aldrich Chemical Co. (Milwaukee, WI). The linear alkanes used were pentane, hexane, heptane, decane, tetradecane, and octadecane, each being at least 95% pure or greater. The mineral oil used in the experiments detailed herein was Soltrol® 130 [Chevron Phillips Chemical Co., The Woodlands, TX], a refined isoparrafin-type mineral oil composed of C₁₀-C₁₃ iso-alkanes, both linear and branched, and having a viscosity of about 1.6 cP.

[0075] Two crude oil samples from Gulf area reservoirs were also used in the tests. The crudes used were North Gulf of Mexico (GOM) condensate and an Auger crude from the Outer Continental Shelf ("OCS") in the Gulf of Mexico, the latter of which was used both raw and cleaned, due to the high water content of the crude when raw. Both of these crude oil samples were supplied by Shell Oil Company (Houston, TX). [0076] For the first set of samples, 99 % pure linear alkanes were used to determine whether THz-TDS could distinguish these hydrocarbon fluids. Soltrol®- 130, which contains chains of C₁₀-C₁₃ alkanes as a mixture of linear and branched alkanes, was also included in this first set. These measurements were obtained using the setup and procedure as described above. All of the samples used were at ambient temperatures with the exception of octadecane (C_1S). Octadecane is essentially a wax near room temperatures and it is heated slightly with a heating plate in order to be able to adjust its path length. It is expected that temperature will influence a sample's characteristics. [0077] The general measurement procedure is as follows. The sample container of FIG. 4 is filled with a known volume of sample, e.g. hexane, and the terahertz time-domain spectrometer (THz-TDS), such as described above in reference to FIG. 3, makes a measurement of a T-ray that has propagated through the sample. After one complete time domain waveform of the T-ray has been acquired, the path length of the sample cell is adjusted as desired, and the process is repeated for multiple (e.g., greater than 2), different path lengths. Generally, and in accordance with the present disclosure, more path lengths result in a higher accuracy of measurements. Thus there are preferably, but not necessarily, 2 path lengths and more preferably at least 3, at least 5, or at least 10 path lengths. [0078] FIG. 6 shows the THz-TDS measurements of a sample of hexane at different path lengths. As the path length increases, the T-rays arrive later in time and their amplitude is reduced. The arrival time of the pulse is linear with path length, which is expected from the equations described above, in particular the equation (8) below, assuming that the refractive index (RI) does not depend on frequency. The amplitude, however, does not decrease exponentially as may be expected, because the absorption coefficient of hexane is frequency dependent and each frequency decays at a different exponential rate.

Example 3: Determination of the Refractive Index for Linear and Mixed Alkanes. [0079] FIG. 7 shows the refractive index of the linear alkanes and Soltrol®-130 as measured by the THz-TDS and as a function of frequency. The refractive index for each sample is nearly constant over the frequency range. This results in a constant time shift of the THz pulse in the time-domain, because each frequency component travels through the sample at the same velocity. The order of these curves is a very interesting feature of these data. Moving from lower to higher refractive indices, the alkanes are lined up in order of chain length with pentane having the shortest length and octadecane having the longest chain length. Soltrol®-130, which contains a mixture of C₁₀-C₁₃ alkanes, falls between tetradecane (C_M) and decane (Ci₀). This is not a surprise as one would expect the refractive index to obey some sort of mixing law.

Example 4: Determination of the Absorption Coefficient for Linear and Mixed Alkanes. [0080] FIG. 8 illustrates the absorption coefficient of the linear alkanes and Soltrol®-130 as a function of frequency. These data have more spectral structure than the refractive index data with the general trend of increasing absorption with increasing frequency. However, the exact character of the curves is in question. The lines cross over each other and have variations with frequency. However, the absorption coefficients of these samples are very small. As a comparison, water has an absorption coefficient on the order of 100 cm-1 or roughly 500 times greater.

Example 5 : Repeatability of Absorption Coefficient and Refractive Index Characterizations .

[0081] Based on the data obtained in Example 4, it was necessary to examine the repeatability of these measurements to check the quality of the data. An experiment was setup where a sample of octane was characterized 4 different times, obtaining both refractive index data and absorption coefficient date: once on March 30, twice on May 24, and once on May 25. The results are shown in FIG. 9 and FIG. 10. The refractive index plot in FIG. 9 shows very good repeatability with very little scatter in the measurements. In comparison to FIG. 7, the separation of these curves is very small. [0082] The absorption coefficient of octane that is shown in FIG. 10, however, has about the same amount of scatter as among the absorption measurements of all the different alkanes in FIG. 8. The absorption measurements on octane do repeat well at around 0.6 THz, around where the power in the THz pulse is the highest. It cannot be concluded, however, that the interesting spectral structure observed in the alkanes of FIG. 9 is definitively "real". The lack of repeatability may be due to alignment issues in the setup and/or the low absorbance of the samples. What is clear, however, is that the sample does not absorb substantially and that absorption increases with frequency. Example 6: Refractive Index Determinations in Mixed Samples and Crudes. [0083] In addition to the pure linear alkanes, measurements were made on samples from actual reservoirs: a north Gulf of Mexico (GOM) condensate and an Auger crude. The Auger crude was cleaned up in a centrifuge prior to analysis in order to remove the water content, which is a strong absorber of T-rays. FIG. 11 illustrates the refractive index as a function of frequency of the two reservoir samples and Soltrol®-130. All of the samples were measured at ambient temperature and unpressurized. There is significant spread between the data with the Auger crude having the largest refractive index and Soltrol®-130 having the smallest. In fact, the Auger crude's refractive index is the largest of all the samples characterized. While it is not clear as to what sample property affects refractive index, each sample is clearly distinguished by this measurement. Example 7: Absorption Coefficient in Crudes.

[0084] FIG. 12 shows the absorption coefficient as a function of frequency (in THz) of the two reservoir samples, North GOM condensate and Clean Crude, and Soltrol®-130. As can be seen from the Figure, below about 0.8 THz, the absorption coefficient for the sample is on the order of what was measured for the linear alkanes (< 0.5 cm^"1). The two reservoir samples are about twice as absorbing as Soltrol®-130. This may be due to residual water content or other contaminants. The most interesting and unexplained feature is the resonance peak at about 0.95 THz. Based on its magnitude and the quality of the data, the peak appears to be a real feature of the data. While the exact cause of the resonance is as of yet unknown, one theory is that the absorption coefficient of all hydrocarbon samples will eventually reach a peak and then decrease and the Auger crude happens to reach its peak in the bandwidth of the measurement. Using a higher bandwidth system to investigate the behavior at higher frequencies and locate resonances can test this theory. Another theory pertains to the presence of aromatics. The Auger crude has a much higher degree of aromaticity than any other previously characterized sample. If these resonances are real, it could potentially provide a robust method for finger printing samples. [0085] Water content can have a substantial effect on the absorption coefficient. FIG. 13 illustrates the absorption coefficient of the reservoir sample from Auger before (raw) and after (clean) the water content is removed. Because the absorption is so high in the raw sample due to the water content, only two path lengths of less than 10 mm are used. As a result, the absorption data on the raw sample contains much more noise than the clean sample. This noise is evident from the bumps and peaks on the raw sample data. Despite the noise, the data clearly show that the clean sample is roughly 2 orders of magnitude less absorbing than the clean data. Indeed, THz-TDS measurements on hydrocarbons are extremely sensitive to water content.

Example 8: Study of Refractive Index versus viscosity of hydrocarbons. [0086] One of the potential applications being considered is using T-rays for inferring viscosity of hydrocarbon samples. This is a challenge for NMR (nuclear magnetic resonance) and OFA (optical fluid analysis), especially with heavier oils. In FIG. 14, the measured refractive index is plotted against the viscosity of linear alkanes. A clear trend appears, where the more viscous alkanes have a higher refractive index. However, there are a couple of caveats that need to be mentioned. At higher viscosity, the trend tends to roll over, which if that continues, may make it difficult to discern the higher viscosities. Also, the samples used are all linear alkanes. It is possible that the refractive index correlates more to some other parameter, such as molecular weight, which may or may not be related to viscosity. These results suggest that the technology and methods described herein have great potential for a variety of applications, as detailed above. Example 9: Analysis of a Mixture of Hydrocarbons.

[0087] As a result of this study, a new method for interpreting these measurements was discovered. As was shown earlier, the index of refraction for most hydrocarbons is distinct and relatively constant over the bandwidth. The refractive index, η(ω), is related to the velocity of light through a material. In the time-domain, the refractive index can also be defined in terms of an arrival time through a fixed path. FIG. 15 illustrates time-domain waveforms of T-rays passing through a 20 mm cuvette filled with various hydrocarbon samples. The pulses that arrive later correspond to samples that have a higher refractive index. For the alkanes, this follows the same trend as shown in FIG. 6, where the longer chain lengths correspond to later arrival times. The north Gulf of Mexico (GOM) condensate sample has the latest arrival time, which is followed by Soltrol®-130. Included in these samples is a mixture of 60 % hexane, 20 % Soltrol®-130, and 20 % pentane. This mixed sample arrives in between Soltrol®-130 and pentane. As is apparent from the data, this time-of-flight (tof) measurement is a simple way to distinguish various samples of hydrocarbons and can be done using only one path length. [0088] The invention has been described in the context of preferred and other embodiments and not every embodiment of the invention has been described. Obvious modifications and alterations to the described embodiments are available to those of ordinary skill in the art. The disclosed and undisclosed embodiments are not intended to limit or restrict the scope or applicability of the invention conceived of by the Applicants, but rather, in conformity with the patent laws, Applicants intends to protect all such modifications and improvements to the full extent that such falls within the scope or range of equivalent of the following claims.

Claims

WHAT IS CLAIMED IS:

1. A method of characterizing a fluid, the method comprising: a) generating a terahertz wave pulse; b) propagating the terahertz wave pulse through the fluid; c) detecting the terahertz wave pulse after it propagates through the fluid over a path having a predetermined path length; d) determining a time-of- flight (tof) of the terahertz wave pulse through the fluid; and e) characterizing the fluid based on the absorption coefficient, the refractive index, or both.

2. The method according to claim 1 wherein step d) includes measuring time-of-flight of the terahertz wave along a plurality of different path lengths.

3. The method according to claim 1 wherein step d) is carried out such that said step e) includes an identification of methane, and an identification of at least one additional hydrocarbon or group of hydrocarbons.

4. The method of claim 1, wherein the terahertz wave pulse generated is in the frequency range from about 0.1 THz to about 10 THz.

5. The method of claim 1, wherein step f) includes measuring at least one parameter selected from the group consisting of chemical composition, asphaltene content, hydrocarbon composition, water contamination, viscosity, gas-to-oil ratio, and API gravity.

6. A system for measuring a parameter of interest in a fluid within a conduit, the system comprising: a measurement assembly associated with the conduit and capable of measuring a property of the fluid flowing through the conduit; a processor for processing data collected by the measurement assembly; and a transmitter for sending the data from the assembly to a receiver, wherein the measurement assembly contains at least one terahertz spectrometer and a fluid container capable of extending over a range of path lengths, and wherein the measurement assembly is a terahertz-time domain system that can generate and detect a Terahertz electromagnetic pulse and which uses a laser to propagate the pulse in free space.

7. The system of claim 6, wherein the properties of the fluid measured by the measurement assembly include viscosity, absorption, concentration, density, and dielectric constant of the fluid flowing through the conduit.

8. A method of investigating a hydrocarbon bearing geological formation traversed by a borehole, comprising: a) acquiring a sample of fluid in the formation with a formation fluid sampling tool located in the borehole, wherein said sample of fluid is a contaminated sample that is contaminated with drilling mud; b) conducting a compositional analysis of the fluid sample located in the sampling tool while said sampling tool is in the borehole, wherein the analysis is carried out using a system as claimed in claim 6 and wherein said compositional analysis includes an identification of methane, and an identification of at least one additional hydrocarbon or group of hydrocarbons; c) relating the compositional analysis to a model of the thermodynamic behavior of the fluid; and d) based on the results generated in step c), predicting a phase behavior of fluid remaining in the formation; wherein step b) includes correcting for said drilling mud contamination in order to obtain an indication of an uncontaminated composition of fluids in the geological formation, and step c) includes relating an uncontaminated composition to said model of said fluid.

9. A method of producing hydrocarbon material from a subterranean formation, the method comprising: a) providing a wellbore extending through at least a portion of the subterranean formation; b) providing a conduit in fluid communication with a hydrocarbon producing zone within the subterranean formation; c) producing a hydrocarbon fluid material from the producing zone; and d) measuring a parameter in the fluid material during production using the method of claim 1, wherein said measuring step is carried out in the borehole.

10. The method according to claim 9 wherein the parameter measured in step d) includes at least one parameter selected from the group consisting of fluid viscosity, fluid water content, concentration, dielectric constant, the API gravity of the fluid, the gas-to-oil ratio (GOR) of the fluid, asphaltene content, and combinations thereof.