Harsh environment in-SITU quantative dissolved co2 measurement

Abstract

Disclosed herein is a downhole tool for in-situ analysis of wellbore fluids, including a MID infrared (IR) emitter configured to emit MID IR light, driver circuitry to modulate the IR emitter to thereby emit MID IR light, optical components to collimate the emitted MID IR light, a reference detector configured to detect the emitted MID IR light, and a sample detector configured to detect the emitted MID IR light after it has passed through the wellbore fluids. An amplifier system converts outputs of the reference detector and the sample detector to reference and sample signal outputs. Control circuitry determines concentration of dissolved C02 in the wellbore fluids based upon the reference and sample signal outputs.

Description

[0001] HARSH ENVIRONMENT IN-SITU QUANTATIVE DISSOLVED CO2 MEASUREMENT

[0002] TECHNICAL FIELD

[0003] This disclosure is directed to the field of the evaluation of carbon dioxide dissolved in downhole fluids in oil and gas operations, and, in particular, to an improved system and method for evaluating dissolved carbon dioxide in-situ.

[0004] BACKGROUND

[0005] Wellbores are drilled deep into the earth to access subterranean reservoirs for the extraction of fluids, such as oil and natural gas. The lifecycle of a well is commonly divided into two main phases, namely the exploration phase and the production phase. The exploration phase involves the initial search for hydrocarbons, including geological surveying and drilling activities to determine the presence and quantity of oil and gas. If the exploration yields positive results, operation transitions to the production phase, which focuses on the efficient extraction of these resources.

[0006] During both phases, obtaining representative samples of reservoir fluids is of interest. In the exploration phase, fluid analysis helps determine the commercial viability of the reservoir by identifying the properties of the fluids, such as chemical composition, pressure, temperature, and flow characteristics. In the production phase, ongoing analysis of these fluids can inform the optimization of extraction processes, the assessment of reservoir depletion, and the management of changes in fluid properties as extraction proceeds.

[0007] Within this context, the identification of carbon dioxide (C02) in reservoir fluids becomes of particular interest. CO2 occurrence within hydrocarbon-bearing formations presents unique challenges to the valuation and subsequent prospect development. This is because C02 can contribute to corrosion, which in turn significantly affects capital and operational expenditures. The corrosive nature of C02, in combination with water, can lead to integrity failures in both the reservoir and surface infrastructure. Moreover, C02 poses concerns for health, safety, and environmental (HSE) integrity. Indeed, 002 is known to be readily absorbed by elastomer seals within sampling and production equipment, thereby reducing their durability and reliability. This absorption weakens the seals' resistance, potentially compromising the integrity of fluid samples and the safety of both equipment and personnel. Conventionally, the evaluation of CO2 content within a hydrocarbon-bearing formation is conducted by extracting fluid samples downhole or at the surface during well tests, which are then sent to a laboratory for analysis. However, this conventional procedure has its limitations due to the reactive nature of C02. Its concentration can be altered significantly through reactions with formation waters, mud filtrates, and other substances before laboratory analysis can be conducted, leading to potentially unreliable data.

[0008] The desire for downhole quantification of C02 stems from various operational needs in the oil industry, such as enhanced oil recovery (EOR) with pressure maintenance using C02 injection, exploitation of improved oil production due to miscible conditions of C02 with oil, and C02 sequestration efforts. Gas analysis in these scenarios is of particular use in determining factors like sweep efficiency in the environmental conditions present downhole. The conventional need for numerous samples and the performance of a large number of laboratory analyses becomes particularly problematic in geologically complex, large, and multi-layered reservoirs. Therefore, the ability to perform real-time analysis to optimize the fluid sampling performed, accounting for the existing fluid complexities, is particularly desired as it would contribute to accurate evaluation and efficient resource management.

[0009] As such, further development is needed.

[0010] SUMMARY

[0011] A downhole tool for in-situ analysis of wellbore fluids that includes a MID infrared (IR) emitter that emits MID infrared (IR) light. The tool has driver circuitry that modulates the IR emitter to emit the MID IR light. The tool includes optical components that collimate the emitted MID IR light. The tool includes a reference detector that detects the emitted MID IR light. The tool has a sample detector that detects the emitted MID IR light after it has passed through the wellbore fluids. The tool includes an amplifier system that converts outputs of the reference detector and the sample detector to reference and sample signal outputs. The tool includes control circuitry that determines concentration of dissolved C02 in the wellbore fluids based upon the reference and sample signal outputs.

[0012] The emitted MID IR light may have a spectrum ranging from 4.3pm to 4.58pm.

[0013] The emitted MID IR light may have a spectrum ranging from 1 pm to 8pm. The driver circuitry may modulate the IR emitter using square wave pulses at a frequency between 0.01 Hz and 5Hz.

[0014] The reference detector may be set at 3.6-4um where there is no CO2 absorption band present.

[0015] The sample detector may be configured to operate within a wavelength range of 4.16pm to 4.36pm.

[0016] The optical components may be configured to provide a path length for the MID IR light through the wellbore fluids between 1 .5mm and 2mm.

[0017] The amplifier system may include a first transimpedance amplifier (TIA) connected to the reference detector. The system may include a second transimpedance amplifier (TIA) connected to the sample detector. The system may include a first variable gain amplifier (VGA) connected to the first TIA. The system may include a second variable gain amplifier (VGA) connected to the second TIA. The system may include a first lock-in amplifier connected to the first VGA. The system may include a second lock-in amplifier connected to the second VGA.

[0018] The control circuitry may be configured to acquire a ratio between the sample signal output and the reference signal output. The circuitry may determine a fluid type based on the ratio. The circuitry may select a corresponding calibration for determining the C02 concentration based on the determined fluid type.

[0019] The control circuitry may be configured to classify the fluid as a gas containing gaseous C02 if the ratio is between 1 and 1 .5.

[0020] The control circuitry may be configured to classify the fluid as water containing absorbed CO2 if the ratio is less than 1 .

[0021] The control circuitry may be configured to classify the fluid as crude oil containing absorbed C02 if the ratio is greater than 1 .5.

[0022] The reference detector and the sample detector may incorporate components using wide bandgap semiconductors or quantum dots.

[0023] A method for in-situ analysis of wellbore fluids that includes emitting modulated MID infrared (IR) light from an IR emitter in a downhole tool. The method includes collimating the emitted MID IR light. The method includes detecting the emitted MID IR light with a reference detector. The method includes passing the emitted MID IR light through the wellbore fluids. The method includes detecting the MID IR light after passing through the wellbore fluids with a sample detector. The method includes converting outputs of the reference detector and the sample detector to reference and sample signal outputs. The method includes determining concentration of dissolved C02 in the wellbore fluids based upon the reference and sample signal outputs.

[0024] The method may further include acquiring pressure and temperature readings of the wellbore fluids. The method may include compensating the determined C02 concentration based on the pressure and temperature readings.

[0025] The method may further include calculating a ratio between a sample detector value and a reference detector value. The method may include determining whether the wellbore fluid is a gas, water, or crude oil based on the ratio. The method may include selecting a corresponding calibration algorithm based on the determined fluid type.

[0026] The determining of the fluid type may include classifying the fluid as gas containing gaseous C02 if the ratio is between 1 and 1 .5. The determining may include classifying the fluid as water containing absorbed C02 if the ratio is less than 1. The determining may include classifying the fluid as crude oil containing absorbed C02 if the ratio is greaterthan 1.5.

[0027] The determining of C02 concentration may include calculating a normalized absorbance value based on the sample detector value, the reference detector value, temperature compensation, and pressure compensation. The determining may include determining the C02 concentration using a calibration formula corresponding to the determined fluid type and concentration range.

[0028] For C02 concentrations less than 7.5%, the C02 concentration may be calculated using the formula: X=[ln(Y-Y0) / A] / R0, where Y is the normalized absorbance.

[0029] For C02 concentrations more than 7.5%, the C02 concentration may be calculated using the formula: X=(Y-o) / y, where Y is the normalized absorbance.

[0030] BRIEF DESCRIPTION OF THE DRAWINGS

[0031] FIG. 1 is a block diagram of a tool for performing MID IR spectroscopy.

[0032] FIG. 2 is a graph showing the effect of path length on MID IR absorbance.

[0033] FIG. 3 is a graph showing is a graph of absorbance vs C02 concentration for different oil types.

[0034] FIG. 4 is a flowchart of the workflow described herein.

[0035] FIG. 5 is a graph showing calibration for the determination of dissolved C02 concentration for different API fluids.

[0036] FIG. 6 is a flowchart for determination of the dissolved C02 concentration. FIG. 7 includes a graph and chart detailing calibration of the C02 concentration calculation for C02 concentrations less than 7.5%.

[0037] FIG. 8 includes a graph and chart detailing calibration of the C02 concentration calculation for C02 concentrations greater than 7.5%.

[0038] FIGS. 9-10 include graphs and charts showing temperature compensation applied in calculation of the CO2 concentration.

[0039] FIG. 11 includes a graph and chart showing pressure compensation applied in calculation of the CO2 concentration.

[0040] FIG. 12 shows a sample lookup table, such as may be used in the workflow of FIG. 6.

[0041] DETAILED DESCRIPTION

[0042] The following disclosure enables a person skilled in the art to make and use the subject matter described herein. The general principles outlined in this disclosure can be applied to embodiments and applications other than those detailed above without departing from the spirit and scope of this disclosure. It is not intended to limit this disclosure to the embodiments shown, but to accord it the widest scope consistent with the principles and features disclosed or suggested herein.

[0043] To overcome the limitations of conventional gas / oil composition analysis, this disclosure introduces an in-situ analytical technique employing differential Mid-Infrared (MID IR) spectroscopy to detect and quantify dissolved carbon dioxide (CO2) in wellbore hydrocarbon mixtures. MID IR spectroscopy operates based upon molecular vibrations that absorb specific wavelengths of light in the mid-infrared range, each unique to different chemical bonds within a molecule, thus providing for a fingerprint for various constituents. The chosen spectral band, from 4.3pm to 4.58pm, aligns with the absorption features of CO2, thereby mitigating potential spectral interference from water vapor and other hydrocarbons. This absorption band can be observed in the graph of FIG. 2.

[0044] With reference to FIG. 1, a tool 10 for performing the MID IR spectroscopy is now described. The tool 10 includes a MID infrared (IR) emitter 13, which is modulated by driver circuitry 12 using a square / sine / triangular wave pulse to maintain a (50%-100%) duty cycle, providing for consistent emission intervals, with a modulation frequency set between 0.01 to 5Hz to match the dynamics of the molecular interactions being observed. The MID infrared (IR) emitter 13 emits light across a spectrum from 1 pm to 8pm, which corresponds to the mid- infrared region where C02 has strong absorption. This IR emitter 13 can be fabricated utilizing Micro-Electro-Mechanical Systems (MEMS) technology or nanorod materials.

[0045] So that the emitted MID IR light interacts as desired with the sample, it is shaped using optical components 14, including reflectors and lenses. These components are arranged to collimate the light to provide for uniformity of the light's interaction with the sample and increase the accuracy of the absorbance measurements by maintaining a consistent path length through the sample. Moreover, a collimated beam of light reduces the dispersion of light, thereby enhancing the spectral resolution.

[0046] The aforementioned path length (that the mid-infrared light travels through the fluid sample) is set between 1.5mm and 2mm such that the light interacts with the fluid neither so weakly as to miss absorption signals nor too strongly to cause saturation of the sample detector, thereby providing for the accuracy and repeatability of the C02 concentration measurements. The effect of path length on absorbance can be seen in FIG. 2.

[0047] The tool 10 utilizes a dual-channel configuration to enhance measurement precision. A reference detector 16, operating within the 3.8pm to 4pm range (e.g., 3.9pm), is utilized to detect and differentiate variations in the composition of hydrocarbons, including changes in API gravity, which is a measure of how heavy or light a petroleum liquid is compared to water. Modifying this parameter allows the system to correct for changes in hydrocarbon density, which could otherwise distort CO2 readings. The sample detector 17 of the tool 10 is used for the direct assessment of the dissolved C02 concentration, and operates within a 4.16pm to 4.36pm range (e.g., 4.26pm).

[0048] Both the reference detector 16 and the sample detector 17 incorporate components using monolithic technologies with wide bandgap semiconductors or quantum dots. Wide bandgap technologies utilize materials that can operate effectively at higher energy levels and are known for their robustness at elevated temperatures. Quantum dots are nanoscale semiconductor particles whose electronic characteristics are closely tied to their size, providing for precise control over their photoresponsive properties. The incorporation of components using either of these technologies provides for a higher sensitivity and stability of the detectors, which it can be appreciates is useful for identifying specific spectral features of CO2 molecules.

[0049] These detectors 16 and 17 are each interfaced with respective Transimpedance Amplifiers (TIAs) 18 and 21, which convert the photocurrent generated by the detectors into a usable voltage signal. The TIA configuration is utilized to counteract the dark current - an inherent baseline current present in detectors even in the absence of light. Note that dark current can increase significantly with temperature, leading to noise that can obscure the true signal; therefore, the TIA configuration utilized herein is calibrated to negate dark current, particularly at elevated temperatures such as 175°C, so that the true signal from the C02 absorption is not compromised.

[0050] The output signals from the TIAs 18 and 21 are passed through respective variable gain amplifiers (VGAs) 19 and 22, providing for adjustment of the amplification factor to match desired signal levels for detection. The resulting amplified signals are then processed by Lock-in Amplifiers 20 and 23, which isolate the specific signal frequency from the noise by synchronizing the detection with a reference frequency - this is known as in-phase detection. The Lock-in Amplifiers 20 and 23 also facilitate heterodyne detection, where two different frequencies are combined to produce a new frequency (e.g., the difference between the two), helping to distinguish between signal and noise. This dual-amplification and filtering substantially improves the signal-to-noise ratio, enhancing the limit of detection for dissolved CO2. This is particularly helpful when dealing with variations in API gravity of fluids, as it provides for accurate 002 measurement across a spectrum of hydrocarbon densities and various gaseous states. The outputs of the Lock-in Amplifiers 20 and 23 are read by controller 11, which performs signal processing to provide for the characterization of absorbed CO2 in the wellbore fluids. This may include the performing of a spline fitting algorithm for multiple ranges of detection, and calibration for pressure and temperature may be performed by the controller 11 as well. Note that the controller 11 also controls the driver circuitry 12.

[0051] The scope of this disclosure extends to the detection of CO2 in different API fluids as well as the handling of gaseous CO2. Indeed, shown in FIG. 3 is a graph of absorbance vs 002 concentration for different oil types.

[0052] With reference to FIG. 4, the workflow proceeds as follows. To perform the characterization of dissolved CO2 in the wellbore fluids, the tool 10 is run or lowered into the wellbore (31), and the MID IR spectroscopy is then performed (32). The characterization of the dissolved CO2 is then performed, including the determination of the concentration of dissolved CO2 (33).

[0053] Calibration for the determination of dissolved CO2 concentration for different API fluids may be performed by the controller 11, for example according to the relationship shown in FIG. 5.

[0054] A sample workflow for determination of the dissolved CO2 concentration by the controller 11 is now described with reference to FIG. 6. Pressure and temperature readings of the fluid are acquired (51) from pressure and temperature sensors on a same tool string as the tool 10, and the values from the sample detector (referred to here as SI ) and reference detector (referred to here as S2) are acquired (52). The values from S1 and S2 are then normalized (53) to account for the different gains of the sample and reference detectors, and the ratio between S1 and S2 is determined (54). If the ratio of S1 / S2 is between 1 and 1 .5, then the fluid is a gas containing gaseous C02 (55), and calibration / compensation is performed based upon a lookup table (56) and the pressure and temperature readings (57) to yield the C02 concentration in the gas. The specific calculations performed will be described hereinbelow, after description of the workflow is complete.

[0055] If the ratio of S1 / S2 is not between 1 and 1.5, then the fluid is a liquid (58) containing absorbed C02. Ifthe ratio of S1 / S2 is less than 1, then the fluid is water (59) containing absorbed C02 (59) assuming confirmation by a sampling tool, for example on the same tool string as the tool 10, that the fluid is in fact water (60); otherwise, the current result can be discarded as an error (61), and diagnostics on the tool can be performed.

[0056] If the ratio of S1 / S2 is greater than 1 .5(62), and if the ratio is greater than a constant X1 (discussed hereinbelow) but less than a constant X2 (discussed hereinbelow) (63), then calibration / compensation to apply for determining the CO2 concentration is selected based on one of two lookup tables (68 or 69), with the selection of lookup table used being based upon a priori knowledge of the type of crude is present in the formation.

[0057] If the ratio of S1 / S2 is greater than 1.5 (62), and if the ratio is greater than the constant X1 (65), then zero absorption of CO2 in the crude known to be present in the formation is defined (67), and the calibration / compensation to apply for determining the CO2 concentration is selected based on one of two lookup tables (68 or 69), with the selection of lookup table being used based upon the a priori knowledge of which type of crude is present in the formation.

[0058] If the ratio of SI / S2 is greater than 1 .5, if the ratio is greater than the constant X2, and if the ratio is less than a constant X3 (discussed hereinbelow) (71) then the calibration / compensation to apply for determining the CO2 concentration is selected based upon one of two lookup tables (68 or 69) , with the selection of lookup table being used based upon the a priori knowledge of which type of crude is present in the formation.

[0059] X1, X2, and X3 are experimental constants for different crude types.

[0060] Calculation of the CO2 concentration and normalized absorbance of CO2 is as follows for gas concentrations of less than 7.5%. Referring to FIG. 7, the CO2 concentration is calculated as:

[0061] X = - , where Y is the normalized absorbance.

[0062] RO

[0063] The normalized absorbance is calculated as: where Refoo / Oco2 @ 25CqSl0 / S20

[0064] Calculation of the C02 concentration and normalized absorbance of C02 is as follows for gas concentrations of more than 7.5%. Referring to FIG. 8, the C02 concentration is calculated as:

[0065] Y-a where Y is the normalized absorbance.

[0066] The normalized absorbance is calculated as: where Refoo / OCQ2 @ 25C- 'sf°ur|d in the selected lookup table.

[0067] Calibration for temperature is as shown in FIGS. 9-10. Calibration for pressure is as shown in FIG. 11 .A sample lookup table is shown in FIG. 12.

[0068] This technology allows real-time CO2 measurements directly in the wellbore, preventing sample alteration that occurs before laboratory testing. With this data, producers can make informed decisions about equipment selection, choosing corrosion-resistant materials where high CO2 levels are detected, and implementing appropriate chemical treatments. Also, the information can guide decisions about CO2 injection rates and patterns in enhanced oil recovery operations, support verification of CO2 sequestration effectiveness, and help optimize fluid sampling strategies in complex reservoirs. Producers can also use the data to schedule preventive maintenance for equipment exposed to CO2, prioritize intervention in wells with problematic CO2 levels, and adjust production parameters to minimize associated risks and costs.

[0069] It is evident that modifications and variations can be made to what has been described and illustrated herein without departing from the scope of this disclosure.

[0070] Although this disclosure has been described with a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, can envision other embodiments that do not deviate from the disclosed scope. Furthermore, skilled persons can envision embodiments that represent various combinations of the embodiments disclosed herein made in various ways.

Claims

CLAIMS1 . A downhole tool for in-situ analysis of wellbore fluids, comprising: a MID infrared (IR) emitter configured to emit MID infrared (IR) light; driver circuitry configured to modulate the IR emitter to thereby emit the MID IR light- optical components configured to collimate the emitted MID IR light; a reference detector configured to detect the emitted MID IR light; a sample detector configured to detect the emitted MID IR light after it has passed through the wellbore fluids; an amplifier system configured to convert outputs of the reference detector and the sample detector to reference and sample signal outputs; and control circuitry configured to determine concentration of dissolved CO2 in the wellbore fluids based upon the reference and sample signal outputs.

2. The downhole tool of claim 1, wherein the emitted MID IR light has a spectrum ranging from 4.3pm to 4.58pm.

3. The downhole tool of claim 1, wherein the emitted MID IR light has a spectrum ranging from 1 pm to 8pm.

4. The downhole tool of claim 1 , wherein the driver circuitry modulates the IR emitter using square wave pulses at a frequency between 0.01 Hz and 5Hz.

5. The downhole tool of claim 1, wherein the reference detector is set at 3.6- 4um where there is no CO2 absorption band present.

6. The downhole tool of claim 1 , wherein the sample detector is configured to operate within a wavelength range of 4.16pm to 4.36pm.

7. The downhole tool of claim 1, wherein the optical components are configured to provide a path length for the MID I R light through the wellbore fluids between 1 .5mm and 2mm.

8. The downhole tool of claim 1 , wherein the amplifier system comprises: a first transimpedance amplifier (TIA) connected to the reference detector; a second transimpedance amplifier (TIA) connected to the sample detector; a first variable gain amplifier (VGA) connected to the first TIA; a second variable gain amplifier (VGA) connected to the second TIA; a first lock-in amplifier connected to the first VGA; and a second lock-in amplifier connected to the second VGA.

9. The downhole tool of claim 1 , wherein the control circuitry is configured to: acquire a ratio between the sample signal output and the reference signal output; determine a fluid type based on the ratio; and select a corresponding calibration for determining the C02 concentration based on the determined fluid type.

10. The downhole tool of claim 9, wherein the control circuitry is configured to classify the fluid as a gas containing gaseous C02 if the ratio is between 1 and 1 .5.11 . The downhole tool of claim 9, wherein the control circuitry is configured to classify the fluid as water containing absorbed CO2 if the ratio is less than 1 .

12. The downhole tool of claim 9, wherein the control circuitry is configured to classify the fluid as crude oil containing absorbed CO2 if the ratio is greater than 1 .5.

13. The downhole tool of claim 1, wherein the reference detector and the sample detector incorporate components using wide bandgap semiconductors or quantum dots.

14. A method for in-situ analysis of wellbore fluids, comprising: emitting modulated MID infrared (IR) light from an IR emitter in a downhole tool; collimating the emitted MID IR light; detecting the emitted MID IR light with a reference detector; passing the emitted MID IR light through the wellbore fluids; detecting the MID IR light after passing through the wellbore fluids with a sample detector;converting outputs of the reference detector and the sample detector to reference and sample signal outputs; and determining concentration of dissolved C02 in the wellbore fluids based upon the reference and sample signal outputs.

15. The method of claim 14, further comprising: acquiring pressure and temperature readings of the wellbore fluids; and compensating the determined C02 concentration based on the pressure and temperature readings.

16. The method of claim 14, further comprising: calculating a ratio between a sample detector value and a reference detector value; determining whether the wellbore fluid is a gas, water, or crude oil based on the ratio; and selecting a corresponding calibration algorithm based on the determined fluid type.

17. The method of claim 16, wherein determining the fluid type comprises: classifying the fluid as gas containing gaseous C02 if the ratio is between 1 and1.5; classifying the fluid as water containing absorbed C02 if the ratio is less than 1 ; and classifying the fluid as crude oil containing absorbed CO2 if the ratio is greater than 1.5.

18. The method of claim 14, wherein determining CO2 concentration comprises: calculating a normalized absorbance value based on the sample detector value, the reference detector value, temperature compensation, and pressure compensation; and determining the CO2 concentration using a calibration formula corresponding to the determined fluid type and concentration range.

19. The method of claim 18, wherein for C02 concentrations less than 7.5%, the C02 concentration is calculated using the formula: X=[ln(Y-Y0) / A] / R0, where Y is the normalized absorbance.

20. The method of claim 18, wherein for C02 concentrations more than 7.5%, the C02 concentration is calculated using the formula: X=(Y-O) / Y, where Y is the normalized absorbance.

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