GB2391940A - Formation fluid tester tool for use in well flow line - Google Patents

Abstract

The formation fluid tester tool, for use in a well flow line to analyse formation fluid during production, comprises an internal reflectance crystal 432 in contact with a fluid 452 in the flow line that includes formation fluid and a first optical channel 420a for carrying monochromatic incident light of a specific wavelength to the crystal. A second optical channel 420b carries light reflected from the internal reflectance crystal, the reflected light being responsive to an absorbance of the formation fluid at the specific wavelength. An optical assembly provides signals indicative of the energy of the incident light and the reflected light and a processor for determining an absorbance of the formation fluid at the wavelength from the signals indicative of the incident light and the reflected light. The source of the monochromatic light preferably comprises an acousto-optical tunable filter (AOTF) which supplies light to the optical channels and a broadband light source which supplies to the AOTF. Also claimed is a method of analysing a formation fluid in a well flow line during production.

Description

t 4' J ( 239 1 940

TITLE:: OPTICAL TOOL AND METHOD FOR

ANALYSIS OF FORMATION FLUIDS

BACKGROUND OF THE INVENTION

1. Related Applications

This application is a continuation-in-part of parent United States Patent Application Ser. No. 09/228,721 filed on January 12, 1999 now pending.

2. Field of the Invention

This invention relates generally to apparatus and methods for analyzing the chemical composition of formation fluids, and more particularly, to apparatus and 10 methods for using infrared spectral analysis to determine the quantities of methane, water and various types of oils in a fonnation fluid.

3. Description of the Related Art

15 In the oil and gas industry, formation testing tools have been used for monitoring formation pressures along a wellbore, obtaining formation fluid samples from the

t r r ( wellbore and predicting performance of reservoirs around the wellbore. Such connation testing tools typically contain an elongated body having an elastomeric packer that is sealingly urged against a zone of interest in the wellbore to collect formation fluid samples in fluid receiving chambers placed in the tool.

Downhole multi-tester instruments have been developed with extensible sampling probes for engaging the borehole wall at the formation of interest for withdrawing fluid samples therefrom and measuring pressure. In downhole instruments of this nature it is typical to provide an internal piston, which is reciprocated hydraulically or electrically to 1O increase the internal volume of a fluid receiving chamber within the instrument aRer a engaging the borehole wall. This action reduces the pressure at the instrument formation interface causing fluid to flow from the formation into the fluid receiving chamber of the instrument. I 5 During drilling of a wellbore, a drilling fluid "mud" is used to facilitate the drilling process and to maintain a pressure in the wellbore greater than the fluid pressure in the formations surrounding the wellbore. This is particularly important when drilling into formations where the pressure is abnonnally high: if the fluid pressure in the borehole drops below the formation pressure, there is a risk of blowout of the well. As a 20 result of this pressure difference, the drilling fluid penetrates into or invades the formations for varying radial depths (referred to generally as invaded zones) depending upon the types of formation and drilling fluid used. The formation testing tools retrieve formation fluids front the desired formations or zones of interest, test the retrieved fluids

r ( to ensure that the retrieved fluid is substantially free of mud filtrates, and collect such fluids in one or more chambers associated with the tool. The collected fluids are brought to the surface and analyzed to determine properties of such fluids and to determine the condition of the zones or formations from where such fluids have been collected.

One feature that all such testers have in common is a fluid sampling probe. This l may consist of a durable rubber pad that is mechanically pressed against the rock formation adjacent the borehole, the pad being pressed hard enough to form a hydraulic i seal. Through the pad is extended one end of a metal tube that also makes contact with 10 the formation. This tube ("probe") is connected to a sample chamber that, in turn, is corrected to a pump that operates to lower the pressure at the attached probe. When the: pressure in the probe is lowered below the pressure of the formation fluids, the formation fluids are drawn through the probe into the well bore to flush the invaded fluids prior to sampling. In some prior an devices, a fluid identification sensor determines when the 15 fluid from the probe consists substantially of formation fluids; then a system of valves, tubes, sample chambers, and pumps makes it possible to recover one or more fluid samples that can be retrieved and analyzed when the sampling device is recovered from 2 the borehole. l 20 United States Patent To. 4,994,071 issued to Safinya et al. discloses a device in which visible and near infrared (JR) analysis of the fluids is done in the borehole, without having to transport recovered samples of the fluid to the surface for chemical analysis.] The IR part of the electromagnetic spectrum ( 0.8 to 25 Am wavelength region, or

equivalently wavenumbers of 12500 to 400 cm't) of a substance contains absotption features due to the molecular vibrations of the constituent molecules. The adsorptions arise from both fundamentals (single quantum transitions occurring in the mid-infrared region from 2.5 - 25.0 m) and combination bands and overtones (multiple quanta 5 transitions occurring in the mid- and the near-infrared region from 0.8 - 2.5 1lm). The position (frequency or wavelength) of these adsorptions contain information as to the types of molecular structures that are present in the material, and the intensity of the adsorptions contains information about the amounts of the molecular types that are present. To use the information in the spectra for the purpose of identifying and 10 quantifying either components orproperties requires that a calibration be performed to establish the relationship between the absorbances and the component or property that is to be estimated. For complex mixtures, where considerable overlap between the adsorptions of individual constituents occurs, such calibrations must be accomplished using various chemometric data analysis methods.

In complex mixtures, each constituent generally gives rise to multiple absorption features corresponding to different vibrational motions. The intensities of these adsorptions will all vary together in a linear fashion as the concentration of the constituent varies. Such features are said to have intensities which are correlated in the 20 frequency (or wavelength) domain. This correlation allows these adsorptions to be mathematically distinguished from random spectral measurement noise which shows no such correlation. The linear algebra computations which separate the correlated absorbance signals from the spectral noise form the basis for techniques such as Principal

( Components Regression (PCR) and Partial Least Squares (PLS). As is well known, PCR is essentially the analytical mathematical procedure of Principal Components Analysis (PCA), followed by regression analysis.

5 PCR and PLS have been used to estimate elemental and chemical compositions and to a lesser extent physical or thermodynamic properties of solids and liquids based on their mid- or near-infrared spectra. These chemometric methods involve: [1] the collection of mid- or near-infrared spectra of a set of representative samples; [2] mathematical treatment of the spectral data to extract the Principal Components or latent 10 variables (e.g. the correlated absorbance signals described above); and [33 regression of these spectral variables against composition and/or property data to build a multivariate model. The analysis of new samples then involves the collection of their spectra, the decomposition of the spectra in teens of the spectral variables, and the application of the regression equation to calculate the composition/properties.

In Saf?nya et al, light in the visible and near IR region is passed through the fluid sample. A spectrometer measures the spectrum of the transmitted and the back scattered light, and knowing the spectrum of the incident light, transmission and backscattered absorption spectra for the sample are determined. Using absorption spectra of water, gas, 20 crude and refined oils, and drilling fluids, a least squares analysis is performed that models the observed spectra as a weighted sum of the spectra of its components, the least squares analysis giving the composition of the fluid in terms of weights of the various components. s

( Safin,a et al. use only the visible and near IR regions that contain only harmonics and combinations of molecular vibrations. The harmonic and combination absorption bands are much weaker than the fundamental absorption bands, and, for this reason, 5 transmission methods of sampling are used to detect absorption spectra. The path lengths through the sample that are necessary to get detectable measurements are large, being typically 5 mm. or more. Even at this length of transmission, signal levels are lower and the spectral analysis of the harmonics and combinations is complicated. Also of importance is the fact that in downhole applications, the presence of particulate matter, 10 microscopic particles or bubbles leads to scattering. This scattering drastically increases the optical density and reduces the ability to detect spectral features of the sample. This effect is discussed below with reference to Figs. 1 and 2.

As noted above, the fundamental absorbencies corresponding to the functional 15 groups of organic chemicals fall in the mid infrared region. The absorbencies are generally strong and to use transmission methods on such fluids would require transmission paths of 25 lam or less. With spacing of this magnitude it is difficult to get good fluid flow through the optical cell. In addition, there are noticeable interference fringes. The method and apparatus of this invention helps overcome this problem.

Diffuse and specular reflectance methods have been used in prior art applications

of near infrared analysis. Diffuse reflectance measurements require a large solid angle of data collection with a relatively large illuminated area to average out sample

inhomogeneities. Consequently, diffuse reflectance is not suitable for measurement of small samples at low flow rates that are characteristic of reservoir fluid monitorin=.

Specular reflectance is used in United States Patent No. 5,167,149 issued to 5 Mullins et al. Disclosed therein is an invention for analyzing the composition of multiphase formation fluids, and specifically for detecting the presence of gas in a flow stream that comprises oil, water, gas or particulates within the borehole, The apparatus comprises a flow line for containing the fluid and a light source for transmitting light towards the fluid in the flow line. A prism transmits light from the source to the fluid and 10 forms an interface with the flow line. The interface reflects the light from the source and a detector array detects the light. The angle of incidence at which total reflection of the light takes place provides a measure of the refractive index of the fluid in contact with the prism surface. As the refractive index of gas and liquids are essentially different, the amount of gas in the fluid can be measured. Specular reflectance methods are effective in 15 identifying the composition of a multiphasic fluid in terms of its constituent phases but are not particularly useful for identifying the chemical composition of a single phase.

However, due to the fact that at sufficiently high pressures, the refractive index of the gas phase approaches the refractive index of liquid hydrocarbons, specular reflectance methods cannot be used to determine methane concentration at high pressures.

TIC United States Patent Application Ser. No. 09/1 11,368 to Weirich et al., which is I assigned to the owner of the present invention, discloses the use of attenuated total reflectance (ATR) methods for analysis of the absorbencies at fundamental frequencies

1 1 for the analysis of borehole fluids, particularly methane in a flow detector. ATR methods make use of the fact that when light is incident at an interface between a first medium of a higher refractive index and a second medium of lower refractive index, there exists a critical angle beyond which total reflectance of the light takes place within the first 5 medium. However, even beyond the critical angle, an evanescent wave is propagated into the second medium with a characteristic depth of penetration do into the second medium given by d _ 2nn2, gsin2 - neat where n 2/ = n / n /, the ratio of the refractive indices of the second and first media and is the wavelength of the radiation in vacuum and the angle exceeds the critical angle.

The energy carried by this evanescent wave manifests itself as a decrease in the 15 energy of the reflected wave, a measurable quantity. ATR methods thus effectively function like the equivalent of a transmission cell having a transmission length do given by do - 0.5 (do + dp) where n', lcosR m2,k-n:2 is the effective thickness for light polarized perpendicular to the plane of incidence and I n2,1 cos on, (I - n,21) \|sin2 - n,2' [(I + {',2,)sin2 - n,2,]

( is the effective thickness for light polarized in the plane of incidence. Some calculations will show that the effective thickness is of the order of the wavelength of the light.

5 Unlike transmission techniques, ATR methods are relatively insensitive to the presence of small particles in the fluid. This advantage of ATR methods is brought out by comparing Figs. 1 and 2 (Pnor art). In both figures, the abscissa is the wavenumber and the ordinate is the absorption. In Fig. 1, the near infrared transmission spectrum of pure silicone oil 102 may be compared with that of silicone oil with 0.015% of TiO2 104 10 and of silicone oil with 0.125% of TiO2 106. As can be seen, the addition of even a small amount of an absorbing material like TiO2 greatly increases the absorption of light and makes it almost impossible to pick out the underlying "signal". In comparison, using ATR techniques, as shown in Fig. 2, the mid infrared absorbance spectrum of pure silicone oil 202 is not significantly affected by the addition of TiO2 204 in quantities as 15 large as 0.5%, much larger than the values used in Fig. 1.

Related United States Patent Application Ser. No. 09/228,721, which is assigned to the owner of the present invention, the entire specification of which is considered

incorporated herein by reference, discloses the use of an optical probe carrying a sapphire 20 crystal which is inserted into the fomafion so as to be in contact with virgin formation fluid. An acousto-optical tunable filter transmits a single wavelength of light from a broadband light source. This monochromatic light is carried by an optic fiber (or channel) to the internal reflectance sapphire crystal where it undergoes total reflection at

the crystal faces in contact with the formation fluid. An evanescent wave propagates into the fluid with a depth of penetration related to the absorption of the light in the fluid.

The reflected light carries information about this absorption. A return fiber conveys the reflected light back to a spectrometer. A processor determines the absorption at the 5 wavelength of the monochromatic light by comparing the energy in the reflected light to the energy in the incident light. By repeating this process at a number of different wavelengths, the absorption spectrum of the fluid is detennined. Principal component analysis of this absorption spectrum using known absorption spectra of chemicals likely to occur in the fluid gives the composition of the fluid in terms of these chemicals.

SUMMARY OF THE INVENTION

The present invention provides an apparatus and a method for determination of 15 the composition of a well fluid that can be drilling fluid, formation fluid or a combination. A fluid sampling probe is inserted into the formation so as to get past the mud cake, the flushed zone and the invaded zone and thus be in contact with virgin formation fluid. At this point, formation fluid is extracted from the formation and transferred to a sample chamber for analysis. An acousto-optical tunable filter transmits a 20 single wavelength of light from a broadband light source. This monochromatic light is carried by an optic fiber to the internal reflectance sapphire crystal where it undergoes total reflection at the crystal faces in contact with the extracted formation fluid. An evanescent wave propagates into the fluid with a depth of penetration related to the

absorption of the light in the fluid. The reflected light carries information about this absorption. A return fiber conveys the reflected light back to a spectrometer. A processor determines the absorption at the wavelength of the monochromatic light by comparing the energy in the reflected light to the energy in the incident light. By 5 repeating this process at a number of different wavelengths, the absorption spectrum of the fluid is determined. Principal component analysis of this absorption spectrum using known absorption spectra of chemicals likely to occur in the fluid gives the composition of the fluid in terms of these chemicals. Another embodiment to be described later in detail utilizes the same principles of operation for analyzing formation fluid and I O providing an additional sensor for measuring wellbore fluid characteristics in a measurement while drilling (MOOD) tool. The MWD tool utilizes an internal reflectance crystal to determine the absorbance characteristics of formation fluid. A sensor is mounted such that the wellbore fluid flowing in the wellbore can be measured as well. A processor determines the absorption at the wavelength of the monochromatic light by 15 comparing the energy in the reflected light to the energy in the incident light for the crystal. The processed data is analyzed and compared to known absorption spectra of drilling fluid and with those of chemicals expected in the return fluid. The processor then compares the characteristics of the formation fluid with the characteristics of the wellbore fluid.

BRIEF DESCRIPTION OF THE, DRAWINGS

For detailed understanding of the present invention, references should be made to 5 the following detailed description of the preferred embodiment, taken in conjunction with

the accompanying drawings, in which like elements have been given like numerals and wherein: FIG. 1 (PRIOR ART) shows the effect of addition of a small amount of a light

10 absorbing material (TiO2) on the absorbance of silicone oil as determined by transmission techniques. FIG. 2 (PRIOR ART) shows the effect of the addition of TiO2 on the absorbance

of silicone oil as determined by attenuated total reflectance (ATR) techniques.

1J 1 FIG. 3 is a simplified schematic illustration of an embodiment of the present invention FIG. 4 is a schematic illustration of the optical probe of the present invention.

FIG. 5 illustrates the optical generator-detector arrangement used in the present invention.

FIG. 6 is a simplified illustration of an MWD embodiment of the present invention. FIG. 7 is a schematic representation of another embodiment of the invention 5 wherein a producing well includes the invention for analyzing formation fluids during production. DESCRIPTION OF THE PREFERRED EMBODIMENT

Referring now to the drawings in more detail, particularly to FIG. 3, there is illustrated schematically a section of a borehole 310 penetrating a portion of the earth formations 311, shown in the vertical direction. Disposed within the borehole 310 by means of a cable or wireline 312 is a sampling and measuring instrument 313 that may 15 include a processor for preprocessing data. The sampling and measuring instrument is comprised of a hydraulic power system 314, a fluid sample storage chamber 315 and a sampling mechanism section 316. Sampling mechanism section 316 includes selectively extensible well engaging pad member 317, a selectively extensible fluid admitting sampling probe member 318 and pumping member 319. The pumping member 319 20 could be located above or below the sampling probe member.

In operation, sampling and measuring instrument 313 is positioned within the borehole 310 by winding or unwinding cable 312 from the hoist 319, around which cable

( 312 is spooled. Depth information from the depth indicator 320 is coupled to signal processor 321 and recorder 322 when instrument 313 is disposed adjacent an earth formation of interest. Electrical control signals from control circuits 323 are transmitted through electrical conductors contained within cable 312 to instrument 313. These 5 electrical control signals activate an operational hydraulic pump (not shown) within the hydraulic power system 314, which provides hydraulic power for instrument operation and which provides hydraulic power causing the well engaging pad member 317 and the fluid sampling probe member 318 to move laterally from instrument 313 into engagement with the earth connation 311 and the pumping member 319. Fluid sampling probe 10 member 318 can then be placed in fluid communication with the earth formation 311 by means of electrical control signals from control circuits 323 selectively activating solenoid valves within instrument 313 for the taking of a sample of any producible connate fluids contained in the earth formation of interest. Samples are then conveyed to the fluid sample storage chamber 315 for downhole testing or retrieval. Not shown is a 15 sealing pad that is used to prevent flow of borehole drilling fluid into the corehole.

For testing the fluid contained in the fluid sample chamber 315, the present invention utilizes an optical probe, which will now be discussed in detail. Turning now to Fig. 4, the optical probe includes a sapphire crystal 432 at its tip connected by means 20 of optical connector 434a to the incoming optical fiber (channeij 420a and the connector 434b to the return optical fiber 420b. The probe housing 436 is mounted to the fluid sample storage chamber section 315so that the internal reflectance crystal 432 contacts the extracted fomnation fluid 452 contained in the fluid sample chamber 315. It should be

( noted here that this invention contemplates the chamber as being any fluid retaining portion of the tool from the point of connation fluid extraction. The different possible configurations would simply require repositioning of the optical probe to the desired location within the tool, which would be obvious to one skilled in the art.

s When light is conveyed into the crystal through optical connector 434a by means of the optical fiber 420a, within the crystal it follows a ray path as indicated by the ray 440, undergoes multiple reflections at points indicated by 442 and 444 and returns through connector 434b to the return fiber 420b.

The internal reflectance crystal must have a high refractive index in the IR region, be chemically resistant and mechanically strong. Sapphire is used in a preferred embodiment of the invention. Sapphire has a refractive index of 1.74. The tapered surface 450 of the crystal is angled at 30 so that the ray 440 exceeds the critical angle at 15 the surface of the crystal with respect to formation fluids that may have refractive indices up to 1.5, and undergoes total reflection. Sapphire is also transparent in the near and mid IR region, chemically resistant, mechanically hard and relatively inexpensive. This makes it the most cost- effective for downhole applications. Cubic zirconia that has characteristics comparable to those of sapphire may also be used. In yet another 20 cmbodimerl; of the invention, tl.e ATR element may be made of diamond. Diamonds are more expensive than sapphires or cubic zirconia, but have the advantage of a higher refractive index, transparency and extreme hardness. By using diamond as the material

( for the ATR, the crystal can be as small is 4 to 8 mm. in diameter and 1- 2 mm in thickness. As would be known to those versed in the art, the electromagnetic field amplitude

5 of the light falls off exponentially with distance from the sapphirefluid interface within the formation fluid, a typical depth of penetration dp (see fonnula above) for this evanescent wave in the fluid being of the order of the wavelength of the incident light.

This evanescent wave is attenuated by the absorption properties of the formation fluid.

Conservation of energy must hold, so that the reflected wave within the crystal 432 has 10 an imprint of this absorption. Thus, by making measurements of the amplitude of the incident light beam in fiber 420a and of the reflected light beam in the fiber 420b, the amount of light absorbed by the fluid at the frequency of the incident light may be determined. 15 Turning now to Fig. 5, the optical assembly 524 includes a broadband light source 560. In a preferred embodiment of the invention, the broadband light source is an incandescent lamp. The light from this broadband light source 560 is passed to an acousto-optical tunable filter (AOTF) 562 that transmits light of a single frequency (or equivalently, having a single wavelength) to the optic fiber 420a, the value of the single 2C frequency being determined by a microwave frequency applied to the AOTF 562 provided by a radio frequency (RF) generator 571. The processor 122 (see Fig. 3) controls this RF generator 571 via leads A (not shown), thus controlling the wavelength of the incident light in the optic fiber 420a. The energy of the monochromatic light in the

optic fiber 420a is measured by a reference detector 564a and this measurement is sent by leads B (not shown) to the processor 122. The light resuming from the optical probe via the optic fiber 420b is passed to the main detector 564b and a signal indicative of the strength of this resuming light is sent to the processor by leads C (not shown).

The operation of the tool may now be understood with reference to Figs. 3S. The tool is positioned on the wireline at a depth at which measurements are to be made.

This may be done either by the surface processor 321 or the downhole processor contained within the instrument 313. Under the control of one of the two processors, the to well engaging pad member 317 and the fluid sampling probe member 318 are activated.

The fluid sampling probe 318 is inserted into the formation to a depth sufficient to extract uncontaminated connation fluid. Those versed in the art would recognize that in order to obtain a proper measurement of the properties of the fo'Tnation fluid, the probe 318 must penetrate into the borehole wall through the mudcake and the invaded zone and into a 15 region where the formation fluid is uncontaminated by drilling fluids. The flow of borehole fluids into the connation may be reduced by use of the sealing pad discussed above but not shown. In addition, in wireline logging applications, a pump at the surface may be used to maintain the borehole at a pressure slightly lower than that of the surrounding formation contamination of the formation with borehole fluids. In an 20 alternate embodiment of the invention,.hc coronation tester too' is pro Aided with a pump in fluid communication with the borehole to maintain a fluid flow out of the formation, thus reducing the risk of contamination of the formation fluid with borehole fluids. Such

r . ( methods of avoiding contamination of formation fluids by borehole fluids would be known to those versed in the art. -

The processor in the downhole instrument 313 is programmed to scan a 5 predefined spectral interval or to obtain data at a number of selected frequencies. For each of the sampled frequencies, the processor directs the RF generator 571 to send a corresponding microwave signal to the AOTF 562 by via a lead A. The broadband light source 560 produces light that covers the entire IR spectral interval, out of which the AOTF 562 filters light at the selected frequency through optic fiber 420a to the probe. At 10 the same time, the processor in the instrument 313 receives a signal indicative of the energy in the light at the selected frequency via lead B. The light at the selected frequency is passed into the sapphire crystal by the optical connector 434a. This light undergoes total reflection at the face of the crystal that is in contact with the formation fluid. The reflected light passes through the optical connector 434b to the optic fiber I 5 420b and thence to the detector 564b. The detector sends a signal to the processor in the instrument 313 via a lead C that is indicative of the energy in the reflected light. s The apparatus is calibrated to account for energy losses in the optic fibers 420a and 420b. This is done by methods that would be familiar to those versed in the art. 20 After cc;npc,,sating for:hc losses in the optic fibers, the ratio of

the signal energy at lead C to the energy at lead B is indicative of the absorption of the fluid at the selected frequency From these measurements, a value of the absorption at the selected frequency is obtained This process is repeated at a number of different values of the selected

( frequency tO give an absorption spectrum for the fluid. As the AOTF wavelengths, controlled by the RF generator, operates at frequencies in the range of 10 to 80 MHZ' one scan through the operating wavelength range takes less than one millisecond, so that more than 100 scans can be performed in less than I second, and subsequently averaged 5 and preprocessed by the downhole processor.

The fluid sample optical probe member 318 is withdrawn from the connation and retracted and the fluid in the fluid sample chamber 315 is expelled from the tool. This expulsion of fluid by the use of pistons operated by either hydraulic or electric power, 10 and these mechanisms are well known to those versed in the art. The well engaging pad member 317 is retracted and the tool is moved to another position in the borehole at which chemical analysis of the formation fluid is to be performed, and the process described above is repeated.

15 The analysis of the data obtained by the apparatus may be carried out by prior art

methods to give a chemical analysis of the connation fluid. One such prior art method

models the observed absorbance spectrum as a weighted sum of a number of components, each having a known absorbance spectrum. The determination of the composition is then a mathematical problem in least squares optimization to determine the weights associated 70 with the components. As long as the number of frequencies at which the abso.-bance is - - -

measured is greater than the number of weights, the equations are determined and a solution may be readily found. Further variations of the method involve the selection of frequencies at which measurements are made: this has the benefit of reducing the time

( spent in making measurements. Principal component analysis may be used to determine those frequencies at which absorbance measurements are most informative. Other variations of the method involve eigenfunction analysis to determine a set of basic eigenspectra that characterize absorbance data within the wavelengths of interest for the S chemicals of interest.

Referencing Fig. 6, an overall simultaneous drilling and logging system that incorporates another embodiment of the present invention is shown wherein measurements are taken on the formation fluid and wellbore fluid 645.

A well 601 is being drilled into the earth under control of surface equipment including a rotary drilling rig 603. In accordance with a conventional arrangement, rig 603 includes a derrick 605, derrick floor 607, draw works 609, hook 611, kelly joint 615, rotary table 617, and drill string 619 that includes drill pipe 621 secured to the lower end 15 of kelly joint 615 and to the upper end of a section of drill collars including an upper drill collar 623, an intermediate drill collar (not separately shown), and a lower drill collar measurement tubular 625 immediately below the intermediate sub. The lower end of measurement tubular 625 carries the sampling mechanism section 316 of the present invention and a drill bit 626. During well drilling operations the drill bit will be a 20 conventional bit when the main purpose to reach a desired depth. A ccringtit will -

replace the conventional drill bit when core samples are desired.

Drilling mud 645 is circulated from a mud pit 627 through a mud pump 629, past a desurger 631. through a mud supply line 633. and into swivel 613. The drilling mud 643 flows down through the kelly joint 615 and an axial central bore in the drill string, and through jets (not shown) in the lower face of the drill bit. The wellbore fluid 645 S containing drilling mud, cuttings and formation fluid flows back up through the annular space between the outer surface of the drill string and the inner surface of the borehole to be circulated to the surface where it is returned to the mud pit through a mud return line 635. A shaker screen (not shown) separates formation cuttings from the drilling mud before the mud is returned to the mud pit.

The overall system in Fig. 6 uses mud pulse telemetry techniques to communicate data from down hole to the surface during drilling operations. To receive data at the surface, there is a transducer 637 in mud supply line 633. This transducer generates electrical signals in response to drilling mud pressure variations, and the electrical signals 15 are transmitted by a surface conductor 639 to a surface electronic data processing system 641. This embodiment may utilize the probe configuration of Fig. 3 with its sampling mechanism section 316, sampling probe 318 and well engaging pad member 3}7 to 20 perform, sampling And testing of the pure Coronation fluid. The sampling and analysis of -

the formation fluid for this embodiment is essentially the same as described herein above with reference to Figs. 3-S. In order to provide more data to analyze the formation fluid parameters of interest, this embodiment provides additional sensors 624 for measuring s

( parameters relating to wellbore fluid 645. The additional sensors may be suited for determining pressure. temperature. resistivity. density. reflectance, etc... These sensors are well known in the art, thus it is not necessary to describe their operation in detail herein. The wellbore sensors may also be adapted for measuring drilling mud flowing in S the drill tube, the annulus of the wellbore, or both for a differential assessment. The thrust of this embodiment is to obtain wellbore fluid characteristics and compare those characteristics with the measured parameters of the formation fluid measured with the AOTF apparatus.

10 Figure 7 is a schematic representation of another embodiment of the invention wherein a producing well includes the invention for analyzing formation fluids during production. In this embodiment, the surface of the earth 700 has a well 702 drilled therein. Well 702 is capped with a conventional wellhead 706 well known in the art, which receives Connation fluids 704 such as oil and/or gas produced from the earth into a 15 well production tube 703. Wellhead 706 then passes those produced fluids into flow line 708. The flow direction ofthe fluid 704 is shown by arrow 712. Flow line 712 carries conventional cut-off valves 710 and regulator 714 so that the flow can be shut off completely by valves 710 or regulated to any desired extent by adjustment of regulator 714 fluid between wellhead 706 and separator system 716. The produced fluids that flow 2Q into separator 716 are segregated into desirable components such as a natural gas - -

component 718 and a separate liquid oil component 720, which are individually recovered from separator 716.

Now referring to Figs. 4 and 7, the optical probe of the present invention includes a sapphire crystal (or any desired internal reflectance crystal with a high refractive index) 432 at its tip connected by means of optical connector 434a to the incoming optical fiber (channel) 420a and the connector 434b to the return optical fiber 420b. The probe 5 housing 436 is mounted to the fluid flow line 708 at any suitable location so that the internal reflectance crystal 432 contacts the produced formation fluid 704 flowing or contained in the fluid flow line 708. It should be noted here that this invention contemplates the fluid flow line 708 as being any fluid retaining portion of the producing well from the point where formation fluid 704 enters the well 702 and production tube 10 703 to and including the separator 716. The different possible configurations would simply require repositioning of the optical probe to the desired location within the tool, which would be obvious to one skilled in the art.

The foregoing description is directed to particular embodiments of the present

15 invention for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope and the spirit of the invention. It is intended that the following claims be interpreted to embrace all such modifications and changes.

Claims (1)

1. ( - 24 Claims

   5 1. A formation fluid tester tool conveyed in a well flow line wherein, in use, said formation fluid tester tool analyzes formation fluid during production, said tool comprising: (a) an internal reflectance crystal in contact 10 with a fluid in said flow line that includes said formation fluid; (b) a first optical channel for carrying monochromatic incident light having a wavelength from a source thereof to the IS internal reflectance crystal; (c) a second optical channel for carrying light reflected from the internal reflectance crystal, said reflected light responsive to an absorbance of the formation fluid at said 20 wavelength; (d) an optical assembly for providing signals indicative of the energy of the incident light and the reflected light; and (e) a processor for determining an absorbance of 25 the formation fluid at said wavelength from the signals indicative of the energy of the incident light and the reflected light.

   2. The formation fluid tester tool of claim 1, wherein 30 the source of the monochromatic light further comprises an acousto-optical tunable filter (AOTF) and a broadband light source on the optical assembly, said AOTF transmitting the incident monochromatic light to the first and second optical channels upon being provided 35 with light from the broadband light source.

   A method of analyzing a formation fluid in a well

   ( - 25 flow line during production, the method comprising: (a) conveying a formation tester tool into the bore in a production flow line; (b) bringing an internal reflectance crystal into 5 contact with the formation fluid flowing in said flow line; (c) conveying in a first optical channel a monochromatic incident light having a wavelength to the internal reflectance crystal 10 and reflecting it therefrom as reflected light into a second optical channel on the probe; (d) providing signals indicative of the energy of the incident and reflected light in the first and second optical channels to a processor; 15 and (e) processing said signals indicative of the; energy of the incident and reflected light in the processor to determine an absorbance of the formation fluid at said wavelength

   - A m Fcs 1 1. A formation tester tool for analyzing a formation fluid in a formation 2 surrounding a wellbore having a borehole fluid, the tester tool comprising: 3 (a) an internal reflectance crystal in contact with a fluid in a sampling 4 chamber that includes said formation fluid; 5 (b) a first optical channel for carrying monochromatic incident light 6 having a wavelength from a source thereof to the internal reflectance 7 crystal; 8 (c) a second optical channel for carrying light reflected from the internal 9 reflectance crystal, said reflected light responsive to an absorbance of 10 the formation fluid at said wavelength; I 1 (d) an optical assembly for providing signals indicative of the energy of 12 the incident light and the reflected light; and 13 (e) a processor for determining an absorbance of the formation fluid at 14 said wavelength from said signals.

   1 2. The formation tester tool of claim 1 wherein the sampling chamber is filled by 2 a sampling mechanism further comprising: 3. (a). a Well engaging pad member; 4 (b) a sampling probe member for extracting formation fluid; and 5 (c) a pumping member for transferring said formation fluid from the 6 formation to the sampling container.

   ( 2,

   1 3 The formation tester tool of claim 2 wherein the first and second optical 2 channels are optic fibers 1 4 The formation tester tool of claim 1 wherein the internal reflectance crystal is 2 made of a material having a high refractive index.

   I 5. The formation tester tool of claim 4 wherein the internal reflectance crystal is I 2 made of a material selected from the group consisting of (i) sapphire, (ii) cubic 3 zirconia, and, (iii) diamond.

   1 6. The formation tester tool of claim I wherein the source of the monochromatic I 2 light further comprises an acousto-optical tunable filter (AOTF) and a 3 broadband light source on the optical assembly, said AOTF transmitting the 4 incident monochromatic light to the first optical channel upon being provided 5 with light from the broadband light source. I 1 7. The formation tester tool of claim 6 wherein said wavelength is determined by 2 a microwave signal to the AOTF from a radio frequency (RF) generator i 3 controlled by the processor.

   1 8. The formation tester tool of claim 1 wherein a surface of the internal 2 reflectance crystal in contact with the formation fluid is angled so that a ray 3 path of the incident light exceeds a critical angle at said surface.

   : HE ( 1 9. The formation tester tool of claim 2 further comprising a wireline for 2 conveying the tool in the wellbore.

   1 10. The formation tester tool of claim 9 wherein the source of the monochromatic 2 light further comprises an acousto-optical tunable filter (AOTF) and a 3 broadband light source on the optical assembly, said AOTF transmitting the 4 incident monochromatic light to the first optical channel upon being provided 5 with light from the broadband light source.

   I 11. A method of analyzing a formation fluid in a formation surrounding a 2 wellbore having a borehole fluid, the method comprising: 3 (a) conveying a formation tester tool into the wellbore; 4 (b) inserting a sampling probe member to extract formation fluid for 5 testing; 6 (c) bringing an internal reflectance crystal into contact with the extracted 7 Connation fluid; (d) conveying in a first optical channel a monochromatic incident light 9 having a wavelength to the internal reflectance crystal and reflecting it 10 therefrom as reflected light into a second optical channel on the probe; I I (e) providing signals indicative of the energy of the incident and reflected 12 light in the first and second optical channels to a processor; and 13 (f) processing said signals indicative of the energy of the incident and 14 reflected light in the processor to determine an absorbance of the 15 formation fluid at said wavelength.

   ( 2q 1 12. The method of claim 1 I wherein the step of reflecting the incident light in the 2 crystal includes a total reflection.

   1 13. The method of claim 11 further comprising generating the monochromatic 2 light for conveying to the crystal by passing light from a broadband light 3 source through an acousto-optical tunable filter (AOTF).

   1 14. The method of claim 13 further comprising sending a microwave signal from a 2 radio frequency (RF) generator under control of the processor to the AOTF, 3 thereby determining the wavelength of the monochromatic light.

   1 15. The method of claim 14 further comprising repeating steps (a) - (f) of claim 11 2 at a plurality of wavelengths of the monochromatic light, thereby obtaining an 3 absorbance spectrum for the formation fluid at said plurality of wavelengths.

   1 16. The method of claim 15 further comprising determining a set of weights for 2 representing said absorbance spectrum of the formation fluid as a weighted 3 sum of absorbance spectra of known constituents.

   1 17. The method of claim 11 further comprising maintaining the drilling fluid at a 2 pressure less than a pressure of the formation fluid.

   : -so 1 18. A MWD forrnatiQn tester tool conveyed on a drill assembly for wellbore fluid 2 and formation fluid from a formation surrounding a wellbore, the tester tool 3 comprising: 4 (a) an internal reflectance crystal in contact with a fluid in a sampling 5 chamber that includes said formation fluid; 6 (b) a first optical channel for carrying monochromatic incident light 7 having a wavelength from a source thereof to the internal reflectance 8 crystal; g (c) a second optical channel for carrying light reflected from the internal 10 reflectance crystal, said reflected light responsive to an absorbance of 11 the Connation fluid at said wavelength; 12 (d) an optical assembly for providing signals indicative of the energy of 13 the incident light and the reflected light; and 14 (e) a sensor for determining a parameter of interest of wellbore fluid;

   15 (f) a processor for determining an absorbance of the formation fluid at 16 said wavelengths from said signals and for comparing said absorbance 17 to said parameter of interest of said wellbore fluid.

   1 19. The MWD formation tester tool of claim 18 wherein the source of the 2 monochromatic light firtler comprises an acousto-ontica! tunable filter 3 (AOTF) and a broadband light source OTT the optical assembly, said AOTF 4 transmitting the incident monochromatic light to the first optical channel upon 5 being provided with light from the broadband light source.

   1 20. A method of analyzing drilling mud flowing within a drill assembly and 2 formation fluid from a formation surrounding a wellbore, the method . 3 compnsmg: 4 (a) conveying a formation tester tool into the wellbore; 5 (b) inserting a sampling probe member to extract Connation fluid for 6 testing; 7 (c) bringing an internal reflectance crystal into contact with the extracted 8 formation fluid; 9 (d) conveying in a first optical channel a monochromatic incident light I O having a wavelength to the internal reflectance crystal and reflecting it 11 therefrom as reflected light into a second optical channel on the probe; 12 (e) providing signals indicative of the energy of the incident and reflected 13 light in the first and second optical channels to a processor;

   14 (f) determining a parameter of interest of wellbore fluid with a sensor, 15 (g) processing said signals in the processor to determine an absorbance of 16 the formation fluid at said wavelength; and 17 (h) comparing said parameter of interest of the wellbore fluid with said 18 absorbance of the Connation fluid using said processor.

   1 21. The metholof claim 20 wherein the step of reflecting the incident light in the 2 crystal includes a total reflection.

   1 22. The method of claim 20 further comprising generating the monochromatic 2 light for conveying to the crystals by passing light from a broadband light 3 source through an acousto-optical tunable filter (AOTF).

   1 23. The method of claim 22 further comprising sending a microwave signal from a 2 radio frequency (RF) generator under control of the processor to the AOTF, 3 thereby detennining the wavelength of the monochromatic light.

   24. The method of claim 23 further comprising repeating steps (a) - (h) of claim 20 at a plurality of wavelengths of the monochromatic light, thereby obtaining an absorbance spectrum for the formation fluid at said plurality of wavelengths. 1 25. The method of claim 24 further comprising determining a set of weights for 2 representing said absorbance spectrum of the formation fluid as a weighted 3 sum of absorbance spectra of known constituents.

   1 26. A formation fluid tester tool conveyed in a well flow line for analyzing 2 formation fluid during production comprising: 3 _ (a) an internal reflectance crystal in contact with a fluid in said flow line 4 that includes said formation fluid; 5 (b) a first optical channel for carrying monochromatic incident light 6 having a wavelength from a source thereof to the internal reflectance 7 crystal:

   : 8 (c) a second optical channel for carrying light reflected from the internal 9 reflectance crystal, said reflected light responsive to an absorbance of 10 the formation fluid at said wavelength; 11 (d) an optical assembly for providing signals indicative of the energy of 12 the incident light and the reflected light; and 13 (e) a processor for determining an absorbance of the formation fluid at 14 said wavelength from the signals indicative of the energy of the 15 incident light and the reflected light.

   1 27. The formation fluid tester tool of claim 26 wherein the source of the 2 monochromatic light further comprises an acousto-optical tunable filter 3 (AOTF) and a broadband light source on the optical assembly, said AOTF 4 transmitting the incident monochromatic light to the first and second optical 5 channels upon being provided with light from the broadband light source.

   1 28. A method of analyzing a formation fluid in a well flow line during production, 2 the method comprising: 3 (a) conveying a formation tester tool into the wellbore in a production 4 flow line; 5 (b) bringing an internal reflectance crystal into contact with the formation 6 fluid flowing in said flow line; 7 tc) conveying in a first optical channel a monochromatic incident light 8 having a wavelength to the internal reflectance crystal and reflecting it 9 therefrom as reflected light into a second optical channel on the probe:

   ', 34c I O (d) providing signals indicative of the energy of the incident and reflected 11 light in the first and second optical channels to a processor: and 12 (e) processing said signals indicative of the energy of the incident and 13 reflected light in the processor to determine an absorbance of the 14 fonnation fluid at said wavelength.