• 专利附录
  • 专利说明
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    • 专利摘要:
    EVALUATION OF CONTAMINATION OF FLUID FORMATION WELL BELOW. The present invention relates to a method of detecting synthetic mud filtrate in a well fluid below including placing a well tool below in a well bore, introducing a sample of fluid from the well below into the well tool below , analyzing the sample of fluid from the well below in the tool below, producing at least two filtrate markers from the analysis of the sample of fluid from the well below and converting at least two filtrate markers by vector rotation to a sufficiently orthogonal sign. The first sample of pumped fluid giving initial plateau readings can be a representative for 100% drilling fluid having an initial orthogonal signal and subsequent samples can be converted into orthogonal signals that are referenced to the first pumped fluid signal to provide a calculation percentage contamination of the formation fluid.
    公开号:BR112013017410B1
    申请号:R112013017410-2
    申请日:2011-01-06
    公开日:2021-01-19
    发明作者:Christopher Michael Jones；Robert E. Engelman；Michael T. Pelletier；Mark A. Proett；Thurairajasingam Rajasingam
    申请人:Halliburton Energy Services, Inc；
    IPC主号:
    专利说明:

    FIELD OF THE INVENTION
    [0001] The present invention generally relates to the analysis of well fluids below in a geological formation. More particularly, the present invention relates to apparatus and methods for analyzing the amount of drilling fluid filtrate present in a forming fluid sample. BACKGROUND OF THE INVENTION
    [0002] Hydrocarbon production wells include well holes that are typically drilled at selected locations in subsurface formations in order to produce hydrocarbons. A drilling fluid, which can also be referred to as "mud", is used when drilling well holes. A drilling fluid is used in drilling a well hole and serves a number of purposes, such as cooling the drill bit, transporting cuts to the surface, providing pressure to maintain well hole stability. and preventing eruptions and sealing the borehole. The well bore must be sealed to minimize the loss of drilling fluids for formation. For safety purposes, most well holes are drilled under conditions of excessive load or excessive pressure, that is, the pressure gradient in the well hole due to the weight of the mud column is greater than the natural pressure gradient of the formation in which the well hole is drilled. Due to the condition of overpressure, the mud penetrates the formation that surrounds the well hole to varying depths, thereby contaminating the neutral fluid contained in the formation.
    [0003] To minimize the loss of drilling fluids for formation, components in the drilling fluid, such as clays, fillers and lost circulation materials, are used to restrict the flow of drilling fluids for formation and to the formation of a filter cake on the well hole wall. The filter cake can provide a seal for the well hole in the formation. Drilling fluids that entered the formation to some extent displaced the forming fluids, which can be referred to as a drilling fluid filtrate.
    [0004] Drilling fluids or muds used for drilling well bores can be water-based or based on an organic compound. Drilling fluids based on organic compost can be further distinguished as being natural-based or synthetic-based. For example, drilling fluids based on organic compost can include natural and / or synthetic hydrocarbons. A drilling fluid based on natural organic compound is one in which the primary component is a natural component that may include hydrocarbons, of a similar nature to those usually produced from fields. Additionally, with recirculation or reuse, drilling fluids can obtain components from the area. Drilling fluids based on natural organic compound can include synthetic components that are added for the printing of certain properties. A drilling fluid based on natural organic compound is one in which the primary component is a natural organic material. A synthetic compound-based drilling fluid is one in which the primary component is a synthetic material. Both drilling fluids based on organic and synthetic compounds can therefore contain one or more synthetic materials that are distinct from the forming fluid that is naturally occurring in the formation. Likewise, synthetic fluids can contain natural components that appear similar to the forming fluid properties. A commonly used drilling fluid is an oil-based mud (OBM). OBM in the context here is to be understood as including synthetic-based oleic sludge or naturally-based oleic sludge, where synthetic non-aqueous liquids form part of the base fluid.
    [0005] Once a well is drilled, it is desirable to obtain formation fluids from areas of interest for analysis and to obtain their properties. If there is a drilling fluid filtrate that has contaminated the well hole area close to the formation, it will alter the analysis of the samples being analyzed and will not be representative of the actual formation fluid. During a pumping of the formation, the first aspirated fluid will be predominantly from the drilling fluid filtrate. To minimize this contamination, the fluids aspirated from the formation are drawn from an isolated area of the well bore along the well, which can be referred to as pumping. As pumping proceeds, the degree of contamination in the samples must decrease over time, and each subsequent sample must increase in the content of formation fluid and decrease in the content of contamination, until a permanent state is obtained.
    [0006] The analysis, techniques and methods are known in the art, which are based on monitoring changes in properties, such as density or resistivity and current optical methods, throughout the pumping, a curve fit of the results, such as through an error function or tangent arc calculations, and obtaining permanent regime approximations with the hypothesis that, when a permanent regime is reached, there will be no contamination.
    [0007] For estimating or determining the type of fluid, including oil and / or gas and / or water and the characteristics of the fluid, in a formation at a particular borehole depth and for estimating the condition of the reservoir surrounding the well hole in particular depth, the well tools below are used during drilling the well hole and after the well hole has been drilled to obtain samples of the well fluid below, also referred to as the forming fluid. The well tools below for use in methods for analyzing well fluids below can be transported to a well bore through a steel cable pipe or a flexible pipe, or any other suitable means. Measuring methods using wire rope tools include lowering a wire rope tool including an analyzer to a well bore to a desired depth. These wire rope tools may contain optical imaging tools for detecting the fluid content of wells below. Other methods for analyzing well fluids below include the profiling method during drilling (LWD) or measurement during drilling (MWD). LWD / MWD are techniques for transporting well profiling tools and / or measuring tools, including the well tools below, to the borehole hole as part of a downhole assembly. When drilling a borehole, these bore tools below are arranged in a borehole assembly above the drill bit. In some methods, the LWD / MWD tools contain optical imaging tools for detecting the fluid content of wells below.
    [0008] To obtain a sample of formation fluid, a probe is often used to withdraw fluid from a formation. However, the forming fluid to a certain depth adjacent to the well bore may be contaminated with the mud or, in other words, contain a mud filtrate. In order to obtain a clean sample of the formation fluid, the formation fluid is removed for a certain period of time after taking the sample. Typically, as the drilling fluid is recycled in a well, the drilling fluid captures the characteristics of the well. Often, the drilling fluid is recycled in a field, and captures the characteristics of the field. Typically, the drilling fluid will contain between 10% and 90% of a natural material from the field. However, the drilling fluid will often retain some of the same characteristics as the base oil, making the amount of contamination from the forming fluid difficult to observe. Inaccurate readings of forming fluid samples can cause costly delays and costly production downtime.
    [0009] Current methods of analyzing fluid from forming filtrate contamination during sampling are based on a curve fit of fluid analysis results, until a quasi-steady state composition is obtained, but a permanent regime composition can be achieved. obtained while significant or even majority contamination is still present.
    [00010] Therefore, there is a need to provide a real-time or near real-time determination of filtrate contamination in a sample of forming fluid. There is also a need to improve the accuracy in determining when a filtrate contamination is at an acceptable level and to decrease the time involved in making that determination. BRIEF DESCRIPTION OF THE DRAWINGS
    [00011] Figure 1 illustrates a partial schematic side view and in partial cross section of a well hole containing a well tool below the invention.
    [00012] Figure 2 describes a partial schematic and partial cross-sectional view of an analysis tool modality.
    [00013] Figure 3 depicts a partial schematic and partial cross-sectional view of a probe drilling collar section of an analysis tool.
    [00014] Figure 4 is a cross-sectional view of an analysis probe modality.
    [00015] Figure 5 describes an alternative cross-sectional view of the probe in Figure 4 in an extended position.
    [00016] Figure 6 shows a partial schematic side view and partial cross section of a well hole containing a well tool under the invention and a processor that are components of a system of the present invention.
    [00017] Figure 7 describes the response in a measured system versus time. DETAILED DESCRIPTION
    [00018] The present invention generally relates to well bore operations. More particularly, the present invention is applicable to investigative well bore profiling and production profiling. The present invention is applicable to well tools below, such as wire rope tools and profiling tools during drilling (LWD) or measuring tools during drilling (MWD), well forming test tools, shank testing. drilling, as well as any other tool capable of being used in a downhole environment.
    [00019] In wire rope measurements, a wire rope tool, such as a downhole tool or a profiling tool, is lowered into an open pit hole in a wire rope. Once lowered to the depth of interest, measurements are made. LWD / MWD tools measure in much the same way as steel wire profiling tools, except that measurements are made by an independent tool near the bottom of the downhole assembly and can be recorded per well is deepened.
    [00020] Figure 1 schematically describes a well tool below, described here as a forming fluid identification tool 10, as part of a well bottom assembly 12, which includes a sub 14 and a drill bit 16 positioned at the most distal end of the forming fluid identification tool 10. During an operation, as shown, the downhole assembly 12 is lowered from a drilling platform 18, such as a ship or other conventional platform, through of a drilling column 20. The drilling column 20 is arranged through an underwater conductor 24 and a wellhead 26. Conventional drilling equipment (not shown) can be supported on a tower 22 and can rotate the drilling column 20 and the drill bit 16, causing the drill bit 16 to form an uncoated well hole 28 through the forming material 30. The perforated well hole 28 penetrates underground areas or reservoir. os, as well as reservoir 32. According to the modalities of the present invention, the formation fluid identification tool 10 can be used in other downhole assemblies and with other drilling devices in a land-based drilling, as well as as in offshore drilling, as described in figure 1. In addition to the formation fluid identification tool 10, the downhole assembly 12 may contain various conventional devices and systems, such as a drilling motor downhole, a rotary steerable tool, a mud pulse telemetry system, LWD / MWD sensors and systems, drill rod testers (DST) and others known in the art. In another embodiment, the forming fluid identification tool 10 and other components described here can be carried down through well hole 28 using wire rope technology or flexible tubing or any other suitable means.
    [00021] With reference to figure 2, one embodiment of the formation fluid identification tool 10 is shown. A first end of the tool 10 includes a drill collar section 100, also referred to as a drill collar collar section 100. For reference purposes, the first end of the tool 10 in the drill collar section 100 is generally the most the tool, which is closest to the distal end of the well hole. The probe collar section 100 may include a forming test apparatus or a forming probe assembly 110 having an extensible sample device or an extensible probe 112. Tool 10 includes a second drill collar section 114, also referred to as a power drill collar section 114, coupled to the drill collar section 100 via an interconnect assembly 116. Interconnect assembly 116 includes a fluid and power / electrical pass-through capabilities, so that the various connections in the interconnect assembly are capable of communicating various fluids, electrical power and / or signals to and from probe collar 100 and power collar 114.
    [00022] In one embodiment, the power collar 114 may include the components of a flushing pump assembly 118, a flow gear or turbine assembly 120, an electronics module 122 and a fluid flow hole diverter. drilling 24. A third drill collar section 126, also referred to as the sample cylinder drill collar section 126, can be attached to the power collar 114. The sample cylinder collar 126 may include one or more sets of sample cylinder 128, 130. A fourth drill collar section 132, also referred to as the terminator drill collar section 132, can be affixed to the sample cylinder collar 126. The coupling between the sample cylinder collar 126 and terminator collar 132 may include an embodiment of an interconnect assembly 134. In an alternative embodiment, terminator collar 132 and interconnect assembly 134 are directly coupled to power collar 114, if a cylinder collar sample 126 is not required. In one embodiment, the formation fluid identification tool 10 can be used in conjunction with drilling operations, well formation tests or drilling rod tests.
    [00023] Referring next to figure 3, a modality of the probe collar section 100 is shown in greater detail. A drill collar 102 houses the formation test or probe set 110. The probe set 110 includes several components for operating probe set 110 for receiving and analyzing formation fluids from the formation of terrain 30 and the reservoir 32. The probe member 140 is arranged in an opening 142 in the drill collar 102 and is extendable beyond the outer surfaces of the drill collar 102, as shown. Probe member 140 is retractable to a position that is aligned with or in recess below the outer surfaces of drill collar 102, as shown in Figure 4. Probe assembly 110 may include an outer recessed portion 103 of the outer surface of drilling collar 102 which is adjacent to probe member 140. The probe assembly may include a sensor 106 for receiving a forming fluid from probe member 140. The forming fluid is communicated from the probe member 140 for sensor 106 via a flow line (not described) for measuring the forming fluid. Also shown is a drilling fluid flow hole 104 through which a drilling fluid can pass.
    [00024] In one embodiment, the well tool below 10 contains a probe collar section 100 that includes a flow line, which may be a pipe or the like, which is isolated from the well bore environment. The function of the well tool below 10 is to recover a sample of formation fluid by pulling a formation fluid from the formation using the probe member 140 of the probe collar section 100. The recovered formation fluid sample by the probe member 140 is sent through the flow line to a sample analyzer, or sensor 106, located in the base part area tool 10. The well tool below 10 also contains an outflow line (not described) ), which is used to remove the tested sample from the well tool below 10 for the well bore environment. The well tool below 10 can also include pump (s) (not described) for moving the forming fluid sample across the entire well tool below.
    [00025] With reference to figure 4, an alternative embodiment is shown as probe 200. Probe 200 is retained in an opening 202 in drill collar 204. Any alternative means for retaining probe 200 are consistent with the teachings here, as understood by someone having common knowledge in the technique. Probe 200 is shown in a stowed position, not extending beyond the outer surface of drill collar 204. Probe 200 may include a rod 206 that has a passage 208 and a piston 210. The end of piston 210 may be equipped with a seal shim 212. Passage 208 communicates with a window 214, which communicates with the flow line (not shown) for receiving and transporting a training fluid to the sample analyzer, or sensor (not shown) . Also shown is a drilling fluid flow hole 220 that allows drilling fluid to flow through drilling collar 204 without contact with probe assembly 200.
    [00026] With reference to figure 5, probe 200 is shown in an extended position. Piston 210 is actuated from a first position shown in figure 1 to a second position shown in figure 5. Seal shim 212 is fitted with wellbore wall surface 222, which may include a mud cake or filter 224, for the formation of a primary seal between the probe 200 and the annular space of well hole 226. The probe 200 can be actuated for the removal of drilling fluids from the formation 230 for a hole 232 for the passage 208 from stem 206 and to window 214. A drilling fluid flow hole 220 is also shown which allows drilling fluid flow through drilling collar 204 without contact with probe assembly 200.
    [00027] Seal pad 212 may be made of an elastomeric material. The elastomeric seal shim 212 seals and prevents drilling fluid or other contaminants from the borehole of the annular space of the borehole 226 from entering the probe 200 during a formation test.
    [00028] The accuracy of the measurements made by the well tools below may depend on the amount of contamination in the sample taken. Drilling fluids used in drilling a well hole can lead to the development of the drilling fluid filtrate in the formation. The drilling fluid filtrate can mix with the forming fluid that is to be tested, resulting in contaminated samples. The contamination of the samples can alter the analysis of the samples being analyzed, making the sample not representative of the actual formation fluid.
    [00029] The methods of the present invention allow the determination of the contamination content of a sample of well-forming fluid below, without a curve fit. During pumping analysis, signal responses are taken and at least one sufficiently orthogonal signal is formed by a vector rotation of two or more signal responses. The sufficiently orthogonal signal can then be used to determine the contamination content of a sample of forming fluid. The sufficiently orthogonal sign can determine if there is a contamination content, even if a steady state condition is achieved. If contamination is still present, the test conditions can be changed, such as flow reduction, to obtain subsequent samples that can be analyzed to determine whether a lower contamination content has been obtained.
    [00030] According to aspects of the invention, as the drilling fluid is recycled in a well, the drilling fluid can capture the constituents of formation fluids in that well. Also, as the drilling fluid is recycled in a field, the drilling fluid can capture the characteristics of the field. A drilling fluid can contain 10% to 90% natural material from the field, such as a forming fluid. However, this contaminated drilling fluid (containing a natural material) will retain some of the same characteristics as the base oil of the drilling fluid. When the base oil is distinct from the contaminated drilling fluid, a response to the 100% drilling fluid filtrate can be characterized even after contamination by using a first pumped fluid sample as a representative for 100% drilling fluid. drilling. The first sample of pumped fluid is analyzed and the initial plateau readings are considered to be all drilling fluid. All the fluid pumped after that can be referred to as the initial plateau of the first fluid pumped for a discrete calculation of percentage contamination. Once a discrete contamination value can be assigned through an orthogonal vector rotation, so can the pure formation fluid signal. The estimate for the pure formation fluid signal improves as the formation fluid concentration increases, but decreases as the signal from the pure sludge disappears. Therefore, the best estimates of a pure formation fluid signal are when a sufficient mixture of drilling fluid filtrate and formation fluid is obtained, which will occur at some point in the pumping sampling.
    [00031] One aspect of the present invention is obtaining signal markers, or, more specifically, vector responses, from pure component end members. The pure component end members represent the initial plateau readings considered to be 100% representative drilling fluid and the estimate 100% pure forming fluid. The comparison of signal responses with previous signal responses acquired from samples with almost the same matrix is a useful way of analyzing the variation, such as samples from the same field. Essentially, the matrix effects between the two samples analyzed are almost identical. Also, the effects of the system and the effects of the instrument are often closer in response to each other, for example, the light source and the detector have not drifted, and the refractive index of the oil is almost identical. The integration of this difference spectrum over short time intervals (as defined by the pumping conditions) allows for a more stable signal throughout the entire pumping.
    [00032] The determination of a pure-forming fluid character is important, because, at some point in the pumping, the concentration of filtrate markers could fall below a tolerable, determinable limit. With both pumping end members determined, a filtrate contamination calculation can still take place. The calculation of filtrate contamination can run without determining the pure components of the drilling fluid or the forming fluid, and can proceed only with the signals. This results in a transfer of calibration requirements from that of component properties to that of changing signal responses. Signal accuracy can be improved by stacking signals. Signal stacking refers to the combination of multiple signals in one signal.
    [00033] In one embodiment, the well tools below the present invention, including the steel cable, a transported pipe and LWD / MWD tools, contain a sample analyzer for analyzing a sample of forming fluid. The well tools below may also contain a pump and flow lines for retrieving a sample of forming fluid from the formation, sending the sample to the sample analyzer and removing the sample from the well tool below after it has been analyzed. .
    [00034] In one embodiment, the sample analyzer can include any type of sample analyzer. In another embodiment, the sample analyzer can be selected from a density analyzer, an electromechanical analyzer, a fluorescence analyzer, an optical analyzer and an acoustic analyzer, and combinations thereof. In one embodiment, the sample analyzer may include an optical analyzer, such as a spectrometer. In one embodiment, the spectrometer includes a light source and a detector. The light source and detector can be selected from all available spectroscopy technologies. In one embodiment, the spectrometer includes a light source and a detector. The light source and detector can be selected from all available spectroscopy technologies. In one embodiment, the sample analyzer can include one or more photometric sensors. In one embodiment, the analyzer contains both optical and non-optical sensors.
    [00035] In one embodiment, the analysis step includes spectroscopy. In one embodiment, any available spectroscopy method can be used in the present invention. In one embodiment, spectroscopy is selected from the group of absorption spectroscopy, fluorescence spectroscopy, X-ray spectroscopy, plasma emission spectroscopy, spark or arc (emission) spectroscopy, visible absorption spectroscopy, ultraviolet spectroscopy ( UV), infrared (IR) spectroscopy, near infrared (NIR) spectroscopy, fluorescence spectroscopy, selectively tuned mass spectroscopy, Raman spectroscopy, coherent anti-Stokes Raman spectroscopy (CARS), nuclear magnetic resonance, photoemission, spectroscopy Mossbauer, acoustic spectroscopy, laser spectroscopy, Fourier transform spectroscopy, and infrared and Fourier transform spectroscopy (FTIR), and combinations thereof. In another modality, spectroscopy is selected from the group of spectroscopy with infrared (IR), spectroscopy with near infrared (NIR), spectroscopy with Fourier transform, and spectroscopy with infrared and Fourier transform (FTIR) and combinations of the same . In a specific modality, spectroscopy is selected from infrared (IR) spectroscopy.
    [00036] In one embodiment, the light source can be selected from the group of a tunable source, a broadband source (BBS), a fiber amplified stimulated emission source (ASE), a blackbody radiation, an improved blackbody radiation, a laser, an infrared, supercontinuous radiation, radiation combined with frequency, fluorescence, phosphorescence and terahertz radiation. A broadband light source is a source containing the full spectrum of wavelengths to be measured. In one embodiment, the light source can include any type of infrared source.
    [00037] In one embodiment, the light source may include a laser diode array. In a laser diode array light source system, the desired wavelengths are generated by individual laser diodes. The output from the laser diode sources can be controlled to provide signals that are arranged together or in a multiplexed manner. In a modality that has a laser diode array light source, a time and / or frequency division multiplexing can be performed on the spectrometer. In one embodiment, a measurement with a trip or an equivalent measurement can be performed with the laser diode array. In one embodiment, an optical cell system of the probe type or sample type can be used.
    [00038] In one embodiment, the spectrometer includes detectors, which act as sensors detecting the light emitted from the light source after the light passes through a sample. The effectiveness of the spectrometer detectors may be dependent on temperature conditions. As temperatures rise, detectors may become less sensitive. The detectors of the present invention can include an improvement in the detector technology. In one embodiment, the detectors of the present invention may have reduced thermal noise, and may have an increased sensitivity to the light emitted. In one embodiment, the detector is selected from the group of thermal cells, photoacoustic detectors, thermoelectric detectors, quantum point detectors, momentary door detectors, combined frequency detectors, high temperature solid door detectors, improved detectors with metamaterials, such as an infinite index of optical refraction.
    [00039] In one embodiment, the spectroscopy of the present invention includes conventional IR spectroscopy. In conventional IR spectroscopy, the light source can also include a divider. In such a modality, the light that is emitted from the light source is divided into two separate beams, in which one beam passes through a sample and the other beam passes through a reference sample. Both beams are subsequently directed to a divider, before being passed to the detector. The divider quickly switches which of the two beams enters the detector. The two signals are then compared in order to detect the composition of the sample.
    [00040] In one embodiment, spectroscopy can be performed by a diffraction grating or an optical filter, which allows a selection of different narrow band wavelengths from a white or broadband light source. In one embodiment, a method of using a broadband source is in conjunction with a fiber Bragg network (FBG). The FBG includes a narrow-band reflection mirror whose wavelength can be controlled by the FBG manufacturing process. In one embodiment, the broadband light source is used in a fiber optic system. In one embodiment, the fiber optic system contains a fiber that has a plurality of FBGs. In such a modality, the broadband source is effectively converted into a plurality of discrete sources having desired wavelengths.
    [00041] In one embodiment, the spectroscopy of the present invention includes a Fourier spectroscopy. Fourier spectroscopy or Fourier transform spectroscopy is a measurement method for collecting spectra. In Fourier transform spectroscopy, instead of passing a monochromatic beam of light through a sample, as in conventional IR spectroscopy, a beam containing multiple different frequencies of light is passed through a sample. This spectroscopy method then measures how much of the beam is absorbed by the sample. Then, the beam is modified to contain a different combination of frequencies, giving a second data point. This process is repeated many times. After the light beams have been passed through the sample, the resulting data is sent to a computer, which can infer from the data what is the absorption at each wavelength. In one embodiment, the beam described above is generated by a broadband light source. The light emitted from the broadband light source shines in a projected mirror configuration, also known as an interferometer, which allows some wavelengths to pass through, but blocks others, due to wave interference. The beam is modified for each new data point by the movement of one of the mirrors; this changes the set of wavelengths that pass through there. As mentioned above, computer processing is used to generate the raw data, which includes the absorption of light for each mirror position in the desired result, which includes the absorption of light for each wavelength. This processing is also known as the “Fourier transform” and the raw data is referred to as the “interferogram”. When a Fourier spectroscopy is used, a scanning process is necessary to create the interferogram. That is, the spectrometer internally generates a fixed and variable length path for the optical beam and then recombines these beams, thereby generating an optical interference. The resulting signal includes an added interference pattern for all frequencies not absorbed by the sample. As a result, the measurement system is not a one shot type system, and hence the sampler type probe is preferred for use with this type of spectrometer. In one embodiment, Fourier spectroscopy is performed using any known light source.
    [00042] In one embodiment, the spectroscopy of the present invention is a Fourier spectroscopy using an ir light source, also referred to as a Fourier transform infrared (FTIR) spectroscopy. In one embodiment, the IR light is guided through an interferometer; the IR light then passes through a sample; and a measured signal is then obtained, called the interferogram. In one embodiment, the Fourier transform is performed on this signal data, which results in a spectrum identical to that from conventional infrared spectroscopy. The benefits of FTIR include faster measurement of a single spectrum. Measurement is faster for FTIR, because information at all frequencies is detected simultaneously. This allows multiple samples to be collected and averaged together, resulting in an improvement in sensitivity.
    [00043] Optical-based signals have been mentioned so far, although other non-optical-based sensors can be used in the present invention. In one embodiment, a sensor based on markers or signals present in the drilling fluid can be used. In one embodiment, the non-optical based sensors used include a signal from a ketone-based sensor, an ester-based sensor and / or an olefin-based sensor. In one embodiment, the sensor can be a selectively tuned mass spectrometer. In one embodiment, the data obtained from the selectively tuned mass spectrometer, the ketone-based sensor, the ester-based sensor and / or the olefin-based sensor signals can be used to measure the percentage contamination of drilling fluid in a sample of forming fluid. As long as the marker or signal changes during pumping, the signals can be measured, the difference in signals over a series at the given time, and these changes manipulated and used for the measurement of percentage contamination, without having readings of curve adjustment over the over time.
    [00044] In one mode, different sensors, optical and non-optical, can be used throughout the pumping to maximize sensitivity. In one embodiment, the pumping is analyzed by spectroscopy, acoustics, electrochemical measurements, density measurements, photometry and / or fluorescence. In one embodiment, density measurements can be used to correlate with optical signals to maximize sensitivity. In another embodiment, a fluorescence can be used for a specific signal, since double bonds can have fluorescence properties.
    [00045] In one embodiment, a sample is taken down well from an isolated section of a well hole wall by a probe section from a well tool below. The sample is sent from the probe section to an analyzer in the well tool below. The sample flows through the analyzer, where it is exposed to light in the medium IR spectrum that produces a first spectral signal of signal magnitude versus wavelength response. The first pumped fluid can be used as a representative for 100% drilling fluid. In one embodiment, the first sample or the first fluid pumped is more than 10% of drilling fluid. In another embodiment, the first sample is 25% to 95% of drilling fluid. In yet another embodiment, the first sample is 90% to 100% drilling fluid. After the first sample is analyzed, subsequent samples are then taken and analyzed. Subsequent samples also flow through the analyzer, where each sample is exposed to light in the medium IR spectrum that produces a first spectral signal of signal magnitude versus wavelength response. The percentage contamination of the sample is calculated by comparing the data from the representative with the subsequent samples. In one embodiment, the calculation is performed without taking curve adjustment readings over time. In one embodiment, 2 or more spectral signals are converted by a vector rotation into a signal sufficiently orthogonal to determine the percentage contamination of the sample.
    [00046] In one embodiment, the first fluid pumped can be used as a representative for 100% drilling fluid. In one embodiment, an alternative embodiment, sample measurements can be reversed curve adjusted for backward extrapolation to an end point of 100% drilling fluid.
    [00047] In one embodiment, during a pumping, one or more sample measurements, such as density, are taken and flows of formation fluid substantially unchanged, which can be referred to as pockets are observed. These pockets may have been located in a portion of the formation that was isolated from the contamination of drilling fluid filtrate, but they were dislodged during pumping and passed through the sensors as flows of a substantially unaltered formation fluid. If these pockets and sample measurements are detected, forming them can be used as a representative for the end point of unchanged formation fluid.
    [00048] Drilling fluids can include natural or synthetic drilling fluids or combinations thereof. In one embodiment, natural drilling fluids are selected from the group of diesel, mineral oil, field oil, and crude oil and combinations thereof. In one embodiment, natural drilling fluids still include synthetic additives. Synthetic additives can contain ketones, alcohols, organic acids, or any mixtures thereof. In one embodiment, synthetic drilling fluids contain esters, olefins, cross-linked polymers or combinations thereof. In one embodiment, esters, olefins or ketones can be used as fingerprints or markers of contamination of drilling fluid in the formation fluids being analyzed. In one embodiment, synthetic drilling fluids contain unknown synthetic components that can be used as another indicator of contamination. Non-limiting examples of components that may be present and used as labels include: emulsifiers, such as a starch or a starch-containing compound; wetting agents, such as phosphorus or a phosphorus-containing compound; corrosion inhibitors, such as amine, thiocyanate or phosphorus and compounds containing them; lubricants, such as an ester or an ester-containing compound; base oils, such as an ester or an ester-containing compound; and fluid loss additives, such as an ester or an ester-containing compound.
    [00049] In one embodiment, the OBM present in the pumping can be identified by the presence of certain components present in the OBM, but not present in a naturally forming fluid. These certain components are synthetic or OBM additives that can be identified by their spectral signals. In one embodiment, these components are selected from esters, ketones and olefins and combinations thereof. Esters, ketones and olefins are typically distinct from natural oils in the medium IR range. These chemicals are the main constituents of a synthetic-based drilling fluid, but are not naturally present in a reservoir. In effect, they can act as chemical markers for determining absolute mud filtrate and, therefore, can be identified as unique synthetic mud markers. Their spectral signals can be monitored throughout the pumping and can be used to determine when drilling fluid contamination has decreased to a sufficient degree. They can be used to determine a pumping end point, as mentioned above. Although signals due to the components of esters, ketones and olefins have been identified as unique markers of mud, if other signal markers can be identified during pumping, they can also be used for contamination level calculations.
    [00050] In one embodiment, the general spectral signal obtained can be converted into a single synthetic fingerprint. In one embodiment, the single synthetic fingerprint is an orthogonal or sufficiently orthogonal fingerprint. During a pumping, the orthogonal synthetic fingerprint decreases at a rate similar to the specific synthetic OBM components or to that of an additive for a synthetic drilling fluid, therefore, it can be used for the measurement of percentage contamination without having readings of adjustment curve over time. In a modality, in order to identify a single fingerprint, the maximum orthogonal descent and / or ascension are calculated.
    [00051] In one mode, in addition to the general spectral signal, any 2 or more spectral signals can be converted by a vector rotation into a single orthogonal synthetic fingerprint, as long as there is a linear relationship between the signal change and the component concentration . In one embodiment, a spectral ketone signal and an olefin spectral signal are present, and their signals can be combined and converted by vector rotation to form a unique orthogonal synthetic fingerprint that will change in relation to the decrease in both signals during a pumping.
    [00052] The modalities may include a combination of spectral and non-spectral signals. The more signals are available for use, the greater the accuracy. In one embodiment, spectral signals are combined with signals from density measurements, ketone-based sensor, ester-based, olefin-based sensor signals, signals from acoustic measurements, signals from fluid conductivity, and fluorescence signals. In another embodiment, spectral signals are combined with signals from density measurements with at least one of the ketone-based, ester-based, and olefin-based signals.
    [00053] Signal responses, measured by spectroscopy and / or by another method, can be sent to a processor. In one embodiment, the processor can be operated to determine the component concentration of the fluid samples through the application of processing techniques. In one embodiment, processing techniques include any known computational method. In one embodiment, any suitable processing techniques can be used to define orthogonal variations. In another embodiment, processing techniques include least squares analysis, partial least squares regression (PLS), multivariate optical element (MOE), main component analysis (PCA), main component regression (PCR ), a multiple linear regression (MLR), classic least squares (CLS), an analysis of variance (ANOVA), a varimax rotation, a singular value decomposition (SVD), a multivariant curve resolution (MCR), a projection of autovector, chemometric methods, and a mixture analysis, and combinations thereof.
    [00054] A multivariant curve resolution (MCR) is a desirable method, which can be used as a processing technique for defining the orthogonal variations of signals of the present invention. MCR is a chemometric technique that can be used to solve an experimental matrix of correlated channel responses (such as optical spectra, mass spectra or chromatograms) in pure response vectors. As applied to optical spectra, the technique is designed to decouple the response of mix spectra into a linear combination of pure component spectra and a matrix of pure component concentrations. The technique can only deal with nonlinear spectral effects with the pretreatment of the pure component matrix. The advantage of the technique is the ability to deal with restrictions in the component domain and in the spectral domain simultaneously with an alternative least squares algorithm. Often, when performing a mixture analysis, where one or more pure components are not strictly measured, the mathematical solution is undetermined ie C * S = X has an infinite number of solutions, where C is the concentration matrix, S is the oxygen reserve unit component spectrum and X is the experimental matrix. The determination of C * Sest = X + R can be determined, with Sest being an estimate of the pure component spectrum, and where R is the residual matrix, by minimizing R and applying restrictions to matrices C and S. When the restrictions can be applied to C and Sest matrices, often an explicit solution can be found.
    [00055] Restrictions can be applied, such as through the physical knowledge of the system. For example, a common set of restrictions applied to MCR solutions is positive spectral and positive concentration restrictions. Typically, these restrictions only lead to a bounded solution with a higher and lower spectral and concentration estimate. Closing restrictions are often used for a mixture in which the sum of the components by volume is assumed to be additive and the total sum of volumes must equal 100%. Although an application of any restriction alone can lead to a boundary that can overlap with a null result (for example, the upper limit of mud contamination in a flow line is 10%, but the actual concentration can be zero), applying both restrictions together often leads to a better-defined solution that does not necessarily override the null result (for example, a maximum sludge concentration is 10%, and the lower limit is 5%). In some cases, positive spectral and concentration restrictions can lead to a unique solution for which the estimate is as certain as the ratio of variance not captured versus that captured (for example, mud contamination is 7.5% + /- 1%). The latter scenario occurs in an unsatisfactory low number of cases. However, many additional or assumed natural restrictions can be applied internally to the solution's mathematics or externally in the algorithm minimization routine, to obtain a discrete solution. Typically, the more constraints that can be applied, the narrower the solution's limits, and the more likely a discrete solution will be found.
    [00056] Restrictions that can be applied include spectral and full concentration restrictions of one end member (for example, assuming that the fluid that first passes through a spectral sensor in a flow line is a 100% filtrate of perforation), baseline restrictions (certain spectral regions are known to not respond to a given component), non-null restrictions, if some spectral regions are known to respond to a component, attenuation restrictions requiring certain spectral regions to increase or decrease monotonically, attenuation restrictions requiring monotonic concentrations to increase or decrease (typically, a mud filtrate decreases in a pumping and a formation fluid increases), and concentration ratio restrictions requiring certain concentrations to maintain a fixed distribution . Restrictions that can be applied include spectral ratio restrictions requiring certain known spectral regions to maintain a fixed relationship (for example, a methane peak in 1680 and a methane peak in 2300), unitary restrictions requiring that the sum of the components be equal at a fixed volume, additional sensor curve shape restrictions (for example, from a density sensor or a resistivity sensor or a capacitance sensor, etc.), and physical restrictions (for example, from phase behavior or state model equation). MCR offers a convenient platform for combining a large amount of system information to provide a solution.
    [00057] The MCR uses a main maximum orthogonal descent where the highest changing spectral variations have the greatest weight, and a maximum variance distribution of the results after an orthogonalization of pure component spectra is rotated, to capture so much concentration information independent as possible given the restrictions. Minor limitations include knowing the number of relevant factors, that is, components or spectral artifacts, and the need for all channel responses to be geometrically linear with respect to component concentrations. The limitation can be tested with a standard factor analysis. If it is found that more than an expected number of factors are influencing the response, any known technique, such as a varimax rotation of the main components, can be used as a representative for a higher-order spectral contribution to facilitate analysis. If the sensor responses are not linear with respect to a pure component concentration, then the concentration or response matrix must be linearized in front of the MCR. For example, resistance can be converted to conductivity, or an optical saturation between 1.4 and 3.0 OD units can be geometrically expanded, or non-linear response regimes can be treated as missing data, while retaining those that fall into a linear regime. This is another advantage of MCR because it can easily handle missing data.
    [00058] For normalization, signals through signal matrix signals that do not have a linear relationship with fluid contamination may need to be forced into a linear or substantially linear relationship through signal processing methods. In one embodiment, signal processing can proceed mathematically, if the signal on a particular channel is defined as: R = B1C + B0 where R is the response, C is the concentration of a component and B1 is the calibration constant, and B0 is a system constant that can derive over time, such that B0 = B (t), but for short periods B0 is approximately constant. The change in concentration of components over time can be described by a parametric equation perhaps of the second order: C = A2t2 + A1t + A0 Therefore, for a short time: R = B1A2t2 + B1A1t + B1A0 + B0 where B1A0 + B0 is approximately a constant. Taking the derivative: R '= B1A2t + B1A1 Integrating and regulating all order 0 constants equal to zero (or to an appropriate value): R = B1A2t2 + B1A1t
    [00059] The effects of the system came out of the equation at the expense of adding noise to the curve (differential signals tend to be more susceptible to noise), although, with a long drift removed, the signal can be stabilized for periods of time longer. The derivative and integral approach is just one example of comparing signals over a series over time. Another approach that can be useful is to take the ratio of signals over a series over time or the ratio of a difference in signals over a series over time.
    [00060] If an initial plateau of signals is not obtained during cleaning, the readings and calculations described above can be used to retrocalculate from the curve fit an estimated initial plateau and a calculated initial end point. The calculated final end point can then be used in the analysis, as described above.
    [00061] In one embodiment, the present invention includes a method for calculating the level of contamination during a pumping without curve adjustment readings. Two or more signal responses are manipulated, such as through vector rotation, to form a single orthogonal synthetic fingerprint, and this fingerprint is used to measure the percentage contamination of a sample.
    [00062] The present invention includes a method for detecting a synthetic mud filtrate in a well fluid below. The method for detecting the synthetic mud filtrate in a well fluid below includes the steps of passing a sample of well fluid below through an analyzer, analyzing the well fluid sample below, producing at least two markers of filtered from the analysis, and the conversion of at least two filtrate markers per vector rotation to a single orthogonal synthetic fingerprint. In one embodiment, a first sample of pumped fluid is analyzed providing readings from the initial plateau that are a representative for 100% drilling fluid, where all the fluid pumped thereafter (the pumping) is analyzed giving readings that are referenced to the starting plateau of first fluid pumped for a discrete calculation of percentage contamination. In one modality, the percentage contamination is obtained without a curve adjustment of the readings following the initial plateau over time. In one embodiment, the step of analyzing the fluid sample from the well below is conducted down the well. In one embodiment, the method for detecting the synthetic mud filtrate in a well fluid below is continuous. In one embodiment, the sample of well fluid below includes from 10% to 90% of forming fluid. In another embodiment, the sample of the formation fluid is obtained from the formation, sent to the analyzer, subjected to an analysis, and then discharged down the well into the well bore. In another embodiment, the fluid sample from the well below is not removed from the well below environment during the measurement method.
    [00063] In one embodiment, the method for detecting synthetic mud filtrate in a well fluid below includes the steps of passing a downstream fluid sample through an analyzer, analyzing the downstream fluid sample by lighting from the well fluid sample below with light from a light source and detecting light passing through the well fluid sample below, and measuring the detected light to produce one or more filtrate markers. In another embodiment, the light emitted from the light source is of a sufficient band for the detection of esters, ketones and / or olefins. In an additional embodiment, the light emitted from the light source is an IR light in the middle range, or MIR.
    [00064] In one embodiment, the method for detecting the synthetic mud filtrate in a well fluid below includes the step of analyzing a sample of well fluid below by using sensors selected from the group of ketone-based , olefin-based and ester-based, and any other synthetic additive for which a sensor produces a single signal, and combinations thereof. In another mode, the analysis step is performed by non-optical sensors. In an additional modality, the non-optical sensors are selected from the group of acoustic measurements, density measurements, fluid resistivity or fluid conductivity and combinations thereof. In one embodiment, the method for detecting synthetic mud filtrate in a well fluid below includes the step of analyzing the sample of well fluid below using optical and non-optical signals.
    [00065] In one embodiment, data is analyzed by comparing signal responses with previous signal responses acquired from samples having essentially the same matrix. In one embodiment, the calculation of filtrate contamination can occur without determining the pure components of the drilling fluid or the forming fluid and can proceed only with signal responses. In one mode, the signals are stacked.
    [00066] In one embodiment, the present invention also includes a method of analyzing a formation fluid contaminated with synthetic mud using spectroscopy. The method of analyzing a formation fluid contaminated with synthetic mud using spectroscopy includes the steps of pumping a sample of formation fluid through an analyzer, analysis of the formation fluid sample by illuminating the formation fluid sample with light at starting from a light source and detecting light passing through the sample of forming fluid, and measuring the detected light to produce one or more filtrate markers, producing at least two filtrate markers from the analysis, and converting at least two filtrate markers per vector rotation to a single orthogonal synthetic fingerprint. In one embodiment, the first sample of pumped fluid is analyzed giving readings from the initial plateau that are a representative for 100% drilling fluid, where all the fluid pumped after that (the pumping) is analyzed providing readings that are referenced to the initial plateau of first fluid pumped for a discrete calculation of percentage contamination. In one modality, the percentage contamination is obtained without a curve adjustment of the readings following the initial plateau over time. In one embodiment, the step of analysis of the sample of the formation fluid is conducted down the well. In one embodiment, the method of analyzing a formation fluid contaminated with synthetic mud using spectroscopy is continuous. In one embodiment, the forming fluid sample includes a forming fluid and a mud filtrate. In one embodiment, the forming fluid sample includes 10% to 90% forming fluid. In an additional embodiment, the sample of the formation fluid is obtained from a formation, sent to the analyzer, subjected to an analysis and then returned down the well to the well hole. In one embodiment, the sample of forming fluid is not removed from the well environment below during the measurement method.
    [00067] In another mode, the light emitted from the light source emits a wide range of wavelengths, in order to obtain a general spectral signal of the pumping. In an additional embodiment, the light emitted from the light source is an IR light in the middle range, or MIR. In another embodiment, the light emitted from the light source includes an IR light in the near range, NIR and MIR. In an alternative embodiment, the light emitted includes a wide range of wavelengths, in order to obtain a general spectral signal of the pumping, and includes a light of sufficient wavelength for the detection of esters, ketones and / or olefins. In an additional modality, the pumping is analyzed by obtaining a sample of formation fluid from a formation, by sending the sample to the analyzer to be subjected to analysis by illumination with an IR light source and then returned down the well to the well hole. In one embodiment, the sample of forming fluid is not removed from the well environment below during the measurement method. In one embodiment, the pumping analysis produces one or more filtrate markers.
    [00068] In one embodiment, the method of analyzing a formation fluid contaminated with synthetic mud using spectroscopy includes the step of analyzing the formation fluid sample by using a combination of spectral and non-spectral signals.
    [00069] The present invention also includes a borehole tool capable of detecting the amount of drilling fluid in a sample of forming fluid directly in a borehole environment. The well tool below includes a pump, an analyzer and a probe, in which the probe obtains a formation fluid from a formation, the pump pulls the formation fluid from the probe through the analyzer and out of the well below, keeping the formation fluid in the well below environment. In one embodiment, the IR light source emits IR light in the mid-infrared range, MIR. In one embodiment, the analyzer is capable of detecting both spectral and non-spectral signals. In one embodiment, non-spectral signals are obtained from non-spectral sensors selected from the group consisting of fluorescence for detecting double bonds, acoustic measurements, density and fluid conductivity measurements and combinations thereof.
    [00070] Figure 6 schematically describes a formation fluid identification tool 10. In one embodiment, an optional processor 11 is part of a downhole assembly 12, which includes a sub 14 and a drill bit 16 positioned at the most distal end of the forming fluid identification tool 10. During an operation, as shown, the downhole assembly 12 is lowered from a drilling platform 18, such as a ship or other conventional platform, via a drilling column 20. The drilling column 20 is arranged through an underwater conductor 24 and a wellhead 26. Conventional drilling equipment (not shown) can be supported on a tower 22 and can rotate the drilling column 20 and the drill bit 16, causing the drill bit 16 to form an uncoated well hole 28 through the forming material 30. The perforated well hole 28 penetrates underground areas or reservoirs, t as well as the reservoir 32. In accordance with the modalities of the present invention, the forming fluid identification tool 10 can be used with a well processor below 11 or an processor above ground 13, or a combination thereof. According to the modalities of the present invention, the forming fluid identification tool 10 and the processor 11 or 13 can be used in other downhole assemblies and with other drilling devices in land-based drilling, as well as in the high seas, as described.
    [00071] The processor may be a computer-based processor and data may be transmitted between the forming fluid identification tool and the processor, in any suitable manner. If a well processor below is used, the resulting data from the well processor below can be transmitted to the surface in any suitable manner, such as by an electrical transmission through a steel cable or the tubular column, pulse signals , pressure signals, etc.
    [00072] One embodiment of the invention is a system for determining the contamination of filtrate in a forming fluid that has a downhole tool with at least one sensor for detecting forming fluid samples and a processor attached to at least a sensor. The processor can analyze the forming fluid samples to produce at least two filtrate markers obtained from the sensor, and can convert at least two filtrate markers by vector rotation to a sufficiently orthogonal signal.
    [00073] The processor can analyze a first sample of pumped formation fluid providing initial plateau readings that are used as a representative for 100% drilling fluid having a sufficiently orthogonal initial signal. The signals from subsequent samples are converted by the computer processor into sufficiently orthogonal signals that are referenced to the initial sufficiently orthogonal signal from the first sample of pumped formation fluid to provide a percentage contamination calculation of the formation fluid.
    [00074] The sensors used in the system can be selected from the group consisting of ketone-based, olefin-based, amide-based, phosphorus-based, amine-based, thiocyanate-based ester, spectroscopic based, non-spectroscopic based, fluorescence based, based on acoustics, based on density, based on fluid conductivity, and combinations thereof. The sensors can use spectral signals, non-spectral signals or combinations of spectral and non-spectral signals, in which the signals are stacked.
    [00075] The system can determine a percentage contamination without adjusting the curve of the filtrate markers over time to predict the percentage contamination at a given point in time. EXAMPLE 1
    [00076] In example 1, a mixing study was conducted, in which a 12 ° API gravity oil was mixed with a diesel-based mud filtrate in a flow loop varying in the concentration of pure diesel to contamination oil low. The final members of oil and diesel spectra are known and have been used for the determination of contamination using a high resolution laboratory spectrometer. The contamination ranged from 100% to approximately 4%. Nonlinearity was less than 6%, which showed that the transmission cell configuration was robust (less than 10% is often considered acceptable). In the 21-minute test, data was collected every second. Once the data has been collected, it has been fed to a simulated real-time processing contamination determination algorithm based on a multivariate curve resolution. In the algorithm, the spectrum of 100% contamination is assumed to be known in the initial moment in the flow experiments, but no hypothesis about the oil spectrum has been made. The spectrum shift is assumed to be due to a gradation between diesel and oil, and the oil spectrum is calculated based on the spectrum shift and a few natural restrictions (the spectra for oil and diesel must be positive, and the diesel sludge filtrate has no asphaltene component). The MCR algorithm determined a final configuration of approximately 2% of contamination. The calculated results are plotted in figure 7 together with the known contamination value versus time. Figure 7 shows a close match between the real-time contamination calculated using the MCR algorithm method described here and the known contamination curve.
    [00077] The terms "base oil" refer to the base fluid, or oil, of the drilling fluid.
    [00078] The terms "drilling fluid" or "drilling mud" refer to a fluid used for drilling well holes in the field.
    [00079] The terms “drilling mud filtrate” or “mud filtrate” refer to the liquid components of the drilling mud that can penetrate a permeable formation, leaving a solid mud cake behind.
    [00080] The terms "filtrate marker" refer to some signal response that can be correlated to a particular drilling mud component or to a particular drilling mud property.
    [00081] The term “orthogonal” means that the scalar product between different signals is zero. Multiple signals are mutually orthogonal only if the scalar products of all possible pairs of different signals are zero.
    [00082] The terms "sufficiently orthogonal" mean that there is an indication of an orthogonal relationship between different signals, but that the scalar products of all possible pairs of the different signals may not be zero.
    [00083] The term “pumping” refers to fluid samples taken during the sampling of well fluids below.
    [00084] The term "spectroscopy" or "spectrometry" is a spectroscopic method used to assess the concentration or quantity of a given chemical species in a sample.
    [00085] The term "spectrometer" refers to the instrument that performs the spectroscopy.
    [00086] Although compositions and methods are described in terms of "comprising", "containing" or "including" various components or steps, the compositions and methods can also "consist essentially of" or "consist of" various components and steps. All of the numbers and ranges shown above may vary by some. Whenever a numeric range with a lower limit and an upper limit is exposed, any number and any included range falling into the range are specifically exposed. In particular, the entire range of values (of the form, "from around aa to b", or, equivalently, "from approximately a to b" or, equivalently, "from approximately b to "Exposed here is to be understood as established for every number and range encompassing the broadest range of values. Also, the terms in the claims have their simple, customary meaning, unless explicitly or clearly defined otherwise by the patent holder.
    [00087] Depending on the context, all references here to "invention" may refer, in some cases, to certain example modalities only. In other cases, you can refer to the subject recited in one or more, but not
    权利要求:
    Claims (22)
    [0001]
    1. Method of detecting synthetic mud filtrate or determining contamination of filtrate in a well fluid below, characterized by the fact that it comprises: the placement of a well tool below (10) in a well hole (28); the introduction of a sample of fluid from the well below in the well tool below (10); analyzing the sample of fluid from the well below in the well tool below (10); the production of at least two filtrate markers from the analysis of the well fluid sample below; and converting at least two filtrate markers by vector rotation to a sufficiently orthogonal signal.
    [0002]
    2. Method according to claim 1, characterized in that the analysis comprises an analysis of a first sample of pumped fluid giving initial plateau readings that are a representative for 100% drilling fluid having a sufficiently orthogonal initial signal.
    [0003]
    3. Method according to claim 2, characterized in that the subsequent samples pumped after the first sample of fluid pumped are converted to sufficiently orthogonal signals that are referenced to the initial sufficiently orthogonal signal from the well tool below (10) to provide a calculation of percentage contamination of the formation fluid.
    [0004]
    4. Method according to claim 1, characterized in that the analysis comprises illuminating the sample of fluid from the well below with light from a light source and detecting light passing through the sample of fluid from the well below , and the measurement of the detected light for the production of one or more filtrate markers.
    [0005]
    5. Method according to claim 4, characterized in that the light emitted from the light source is of sufficient wavelength for the detection of components selected from the group consisting of esters, ketones, olefins, amides, phosphorus, amines, thiocyanate and combinations thereof.
    [0006]
    6. Method according to claim 4, characterized in that the light source is an infrared light source producing infrared light.
    [0007]
    7. Method according to claim 6, characterized in that the infrared light comprises wavelengths in a medium infrared range.
    [0008]
    8. Method, according to claim 1, characterized by the fact that the analysis includes the use of non-spectroscopic sensors selected from the group of ketone-based, olefin-based, amide-based, phosphorus-based, amine-based, thiocyanate-based, ester-based and combinations thereof.
    [0009]
    9. Method, according to claim 3, characterized by the fact that the percentage contamination is obtained without adjusting the curve of the filtrate markers over time to predict the percentage contamination at a given point in time.
    [0010]
    10. System for the determination of filtrate contamination in a formation fluid, characterized by the fact that it comprises: a well tool below (10) that comprises at least one sensor (106) for the detection of samples of formation fluid; a processor (11, 13) coupled to at least one sensor (106); wherein the processor (11, 13) can analyze the forming fluid samples to produce at least two filtrate markers from data obtained from at least one sensor (106) and can convert at least two markers of filtrate filtered by vector rotation in a sufficiently orthogonal signal.
    [0011]
    11. System according to claim 10, characterized by the fact that the processor (11, 13) can analyze a first sample of pumped formation fluid giving initial plateau readings that are a representative for 100% drilling fluid having a sufficiently orthogonal initial sign.
    [0012]
    12. System according to claim 11, characterized in that the signals from subsequent samples pumped after the first sample of pumped formation fluid are converted by the computer processor to sufficiently orthogonal signals that are referenced to the sufficiently orthogonal initial signal of the first sample of formation fluid pumped to provide a percentage contamination calculation of the formation fluid.
    [0013]
    13. System, according to claim 10, characterized by the fact that the sensors (106) are selected from the group consisting of ketone-based, amide-based, phosphorus-based, amine-based, thiocyanate based, ester based, based on spectroscopy, based on non-spectroscopy, based on fluorescence, based on acoustics, based on density, based on fluid conductivity, and combinations thereof.
    [0014]
    14. System according to claim 10, characterized in that the sensors (106) use spectral signals, non-spectral signals, or combinations of spectral and non-spectral signals, in which the signals are stacked.
    [0015]
    15. System, according to claim 10, characterized by the fact that the percentage contamination is obtained without adjusting the curve of the filtrate markers over time to predict the percentage contamination at a given point in time.
    [0016]
    16. Method of analysis of a formation fluid contaminated with synthetic mud using spectroscopy, characterized by the fact that it comprises: the placement of a well tool below (10) in a well hole (28); the introduction of a sample of formation fluid in the well tool below (10); analyzing the sample of the formation fluid in the well tool below (10) by illuminating the sample of the formation fluid by emitting light from a light source; detecting light passing through the sample of forming fluid; and measuring the detected light to produce at least two filtrate markers; and converting at least two filtrate markers per vector rotation to a sufficiently orthogonal signal.
    [0017]
    17. Method according to claim 16, characterized in that the analysis comprises the analysis of a first sample of pumped formation fluid that provides initial plateau readings that are a representative for 100% drilling fluid having a sufficient signal initial orthogonal.
    [0018]
    18. Method according to claim 17, characterized in that the subsequent samples pumped after the first sample of pumped formation fluid are converted into sufficiently orthogonal signals that are referenced to the initial sufficiently orthogonal signal of the first pumped formation fluid sample to provide a calculation of percentage contamination of the forming fluid.
    [0019]
    19. Method according to claim 16, characterized in that the light emitted from the light source is of sufficient wavelength for the detection of components selected from the group consisting of esters, ketones, amides, phosphorus , amines, thiocyanates, olefins and combinations thereof.
    [0020]
    20. Method, according to claim 16, characterized by the fact that the analysis still includes the use of non-spectroscopic sensors selected from the group consisting of ketone-based, olefin-based, amide-based, based on phosphorus, based on amine, based on thiocyanate, based on ester, based on fluorescence, based on acoustics, based on density, based on fluid conductivity, and combinations thereof.
    [0021]
    21. Method according to claim 16, characterized in that the analysis is performed using spectral signals, non-spectral signals or combinations of spectral and non-spectral signals, in which the signals are stacked.
    [0022]
    22. Method, according to claim 16, characterized by the fact that the percentage contamination is obtained without adjusting the curve of the filtrate markers over time to predict the percentage contamination at a given point in time.
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    法律状态:
    2019-01-08| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|
    2019-08-27| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    2020-10-13| B06A| Patent application procedure suspended [chapter 6.1 patent gazette]|
    2020-12-22| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2021-01-19| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 10 (DEZ) ANOS CONTADOS A PARTIR DE 19/01/2021, OBSERVADAS AS CONDICOES LEGAIS. |
    2021-08-17| B16C| Correction of notification of the grant|Free format text: REF. RPI 2611 DE 19/01/2021 QUANTO AO RELATORIO DESCRITIVO. |
    优先权:
    申请号 | 申请日 | 专利标题
    PCT/US2011/020312|WO2012094007A2|2011-01-06|2011-01-06|Downhole formation fluid contamination assessment|
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