Untitled record

full description

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The present disclosure relates to systems and methods for measuring the gas content of drilling fluids.

While drilling a hydrocarbon producing well, the drilling fluid or 'mud' circulates continually from the surface to the bottom of the drilled well bore and back to the surface. As the drilling fluid does

<p>5 It has several functions, one of which is to transport wellbore extractors to the surface where they are separated from the drilling fluid. Another function of drilling fluid is to cool the drill bit and provide hydrostatic pressure on the wall of the drill hole to prevent borehole collapse and the resulting flow of gas or liquid from the formations being drilled.</p>

The analysis of the drilling fluid upon its return to the surface is well known in the oil and gas industry as a first-of-its-kind assessment

<p>10 Importance of an area of ​​reservoir containing hydrocarbons, and therefore data of interest are provided to guide subsequent evaluation and testing. The mentioned analysis and testing are generally referred to as Mud logging analysis. By logging mud performance, reservoir areas during penetration can be assessed initially by measuring the formation gases present in the drilling fluid as it returns to the surface. The presence and concentration of hydrocarbon and non-hydrocarbon gases present in drilling fluids can be used</p>

<p>15th For depth in the design of incentives and production processes, as well as in evaluation.</p>

Mud performance logging analysis is typically performed off-line using laboratory analyzes that require extraction of a sample of drilling fluid and a subsequent controlled test is usually performed at a separate site. Because the properties of a sample extracted from drilling fluid typically change during the time lag between collection and analysis, retrospective analyzes can be far from unsatisfactory for characterization

<p>20 real drilling fluid.</p>

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Additionally, some clay performance logging analyzes take hours to days to complete. Thus, the drilling process is usually completed before the analysis is completed. As a result, proactive control of drilling operations cannot occur, at least without significant process disruption while awaiting the results of mud performance logging analyses.

<p>5 US Patent No. 20130033702 relates to systems and methods for analyzing the oil/gas separation process. One method involves transferring a fluid to a fluid separator coupled to a flow path, wherein the fluid separator includes an inlet and a drain stream, producing a first output signal corresponding to a characteristic of the fluid adjacent to the inlet using a first optical computer, producing a second output signal corresponding to the fluid characteristic adjacent to the drain stream using a first computer. Second Optical Computer, Receiver</p>

<p>10 The first and second output signals using a signal processor in connection, producing an output signal</p>

Using a signal processor, which indicates the fluid property changing between the inlet and the drain. US Patent No. 20110313670 relates to a method and apparatus for developing new types of hydrocarbons and a method and apparatus for releasing gases from a drilling fluid. More specifically it relates to a gas analyzer for the development of new types of any one or more methane, ethane, propane, butane

<p>15th and pentane transported in a drilling fluid, at a gas trap that can be used with a gas analyzer. International Application No. 01982002573 relates to methods and apparatus for analyzing substances in or out of a well bore and providing results of analysis as a function of borehole depth, and to facilitate well development.</p>

General description of the invention

The present disclosure relates to systems and methods for measuring gas content in drilling fluids in real time using

<p>20 Optical computer aids that can be calibrated in real time, which can provide more accurate gas content measurements. Gas content measurements can be used to adjust one or more drilling variables in response to them.</p>

The systems and methods described herein use various configurations and arrangements of optical computational devices, also referred to as "opticoanalytical devices,"

<p>25 To analyze a material of interest in real or near real time. About operating, can</p>

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Illustrative systems and methods are otherwise useful for determining one or more properties or characteristics of the fluid, such as the type and concentration of one or more gases present in the fluid. This can allow qualitative and/or quantitative analyzes of the fluid to be performed without the need to extract a sample and to perform time-consuming analyzes on the sample in an off-site laboratory, which may be particularly advantageous

<p>5 To record clay performance in real time.</p>

The systems and methods disclosed herein could be for use in the oil and gas industry since the optical computational methods described provide an economically feasible, challenging, and accurate means of monitoring oil/gas-related fluids, such as drilling fluids. Specifically, systems and methods can be demonstrated to be effective for use in gas analysis by recording slurry performance, thus providing a continuous data stream on gas analysis.

<p>10 Hydrocarbon and non-hydrocarbon gas types that may be exposed while drilling underground formations. When drilling fluid returns to the surface, for example, it can contain hydrocarbons (and other compounds) embedded in the drilled rock along with additional hydrocarbons that may have seeped into the wellbore from the surrounding rock formation. Real-time measurement will result in abundance The gaseous compounds listed provide information regarding the hydrocarbon content of the rocks.</p>

<p>15th However, in some cases it may be difficult to measure some types of gas present in the drilling fluid, for example, due to the low concentration of the gas of interest, due to the high concentration of another gas (for example, methane) that interferes with detection (for example, for example, has an interfering spectrum), or a combination thereof. Accordingly, in some cases, optical computer methods may optionally be used in combination with other analytical methods to analyze reference gases present in</p>

<p>20 Drilling fluid and any gas of interest contained in the gas extracted from the drilling fluid. Then, the concentration of the reference gases present in the drilling fluid and in the extracted gas can be compared and correlated with a correction factor or correction function. Then, the correction factor/function can be used to derive the concentration of each gas of interest in the drilling fluid from the concentration of each gas of interest present in the extracted gas. These or similar methods can provide a more accurate real-time performance logging of mud at a site</p>

25 well.

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Brief explanation of the drawings

The following figures are included to illustrate certain aspects of the present disclosure, and are not to be viewed as exclusive embodiments. Many modifications, changes, combinations and equivalents in form and function can be made to the technical subject that has been revealed, as will become clear to those skilled in the field

<p>5 Once you take advantage of this disclosure.</p>

Figure 1 is an illustrative embedded computer element, according to one or more embodiments.

Figure 2 is an optical computer illustrative of a fluid monitor, according to one or more embodiments.

Figure 3 is another illustrative optical computational method of observing a fluid, according to one or more of the

<p>10 embodiments.</p>

Figure 4 is an illustrative wellbore drilling assembly which may use one or more optical computational methods for fluid monitoring, according to one or more embodiments.

Figure 5 is an illustrative representation of a part of a system suitable for deriving a double-point correction factor for the gas-fluid composition, according to one or more embodiments.

<p>15th Figure 6 is an illustrative well-bore drilling assembly with optical computer aids for an observation of a drilling fluid or a completion fluid, according to one or more embodiments.</p>

Detailed description:

In some embodiments, the gas degassing from the drilling fluid may be analyzed at the surface, outside the stringent environmental conditions down the well (high pressure, high temperature, strong vibration).

<p>20 Therefore, customized and advanced measurement techniques may be available for the analysis of the extracted gas, such as photometric techniques, gas chromatography, and the like. Furthermore, a range of surface-to-surface measurement techniques can be used on the extracted gas sample when overlapping signals</p>

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of two different components with each other using a single measurement technique. For example, when the optical signature of two compounds overlaps each other, the gas sulfur method can be to clearly separate both compounds and provide an accurate measurement value for them. In this regard, systems and methods compatible with the current detection allow to obtain a measurement of gas concentration in

<p>5 Drilling fluid at a downhole location, based on a measurement of the gas concentration in the extracted gas at the surface.</p>

Information regarding the hydrocarbon content of the rocks can be provided to the well operator for interpretation and consideration and, if necessary, the well operator can vary several drilling or completion parameters in response. For example, based on

<p>10 Gas types and concentrations of gases detected in drilled rock, the well operator can adjust production valves and/or throttle settings to clean drilling progress and also to minimize well bore rush by early burst detection. In other cases, the operator may alter the properties of the mud in order to improve drilling efficiency or the effectiveness of formation evaluation. It includes other drilling and completion variables that can be changed by the operator</p>

<p>15th Operation of the well once the data is taken into account Change a cementing program and/or casing layout and improve the design of a well completion.</p>

In some cases, the data can reveal excessive amounts of dangerous or otherwise toxic gases returning to the surface. These gases may pose a potential health hazard to rig workers and the surrounding environment. In these cases, the well operator can proactively reduce the amount of

<p>20 Dangerous/toxic gases by introducing one or more special additives or components</p>

by treatment to the drilling fluid.

In other cases, the data may indicate an excess amount of bio-hydrocarbons in the drilled borehole, such as in a specific lateral course of the wellbore. In these cases, the well operator can manipulate the well plan and/or ground routing so that the resulting wellbore is shaped to an extent

<p>25 Significant in and through the strata or area of ​​observation rich in hydrocarbons. In other words, it can be treated</p>

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The planned course of the well path or otherwise altered by orienting the drilling equipment underground so that the borehole penetrates a greater portion of the hydrocarbon rich strata than would otherwise have been penetrated.

As used herein, the term "fluid" refers to any substance that is capable of flowing, including particulate solids, liquids, gases, slurry mixtures, emulsions, powders, slurries,

<p>5 mixtures, combinations thereof, and the like. In some embodiments, the fluid is a drilling fluid or "mud", and includes water-based drilling fluids, oil-based drilling fluids, synthetic drilling fluids, and the like. In other embodiments, the fluid may be a completion fluid or a cleaning fluid such as, but is not limited to, fresh water, brine (for example, water containing one or more salts dissolved in it), barine (for example, saturated salt water, chloride salts, bromide salts,</p>

<p>10 combinations thereof, and so on), sea water, separator fluid, base fluids, or other treatment fluids known in the art.</p>

As used herein, the term "property" refers to a chemical, mechanical, or physical characteristic of a fluid. A fluid property can include a value or quantitative concentration of one or more chemical components or compounds present in the fluid. These chemical components may be referred to here as "decomposition products."

<p>15th The illustrative properties of an optically computer-observed substance disclosed herein may include, for example, chemical composition (for example, identity and total concentration or for individual components or compounds), presence of phases (for example, gas, oil, water, etc.), impurity content, pH, alkalinity, viscosity, density, ionic strength, total dissolved solids, salt content (eg.</p>

<p>20 For example, salinity, porosity, opacity, bacterial content, total hardness, combinations thereof, state of matter (solid, liquid, gaseous, emulsion, mixtures, and so on), and the like.</p>

Furthermore, the phrase “property of interest to/in a fluid” may be used here to refer to a concentration or property of a gas present in or otherwise retained in the fluid. includes demonstration gases that can be monitored or otherwise measured using optical computer aids embedded in the drilling fluid,

<p>25 eg, but not limited to, methane, ethane, propane,</p>

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n-butane, n-pentane, iso-butane, iso-pentane, neo-pentane, benzene, toluene, carbon dioxide, carbon monoxide, hydrogen sulfide, acetic acid argon, helium, oxygen, nitrogen 5, water, hydrogen, carbonyl sulfide, carbon disulfide

disulfide, and any combination thereof.

As used herein, the term "flow path" refers to a path by which the fluid is able to travel between at least two points. In some cases, the flow path need not be continuous or contiguous between the two points. Illustrative flow paths include, but are not limited to, a flow line, a line

<p>10 Tubing, production tubing, drill string tubing, running tubing string, casing, borehole, specific annular space between a wellbore and any tubing placed within the borehole, mud bore, subterranean formation, and so on, combinations thereof, or the like. It should be realized that the term "flow path" does not necessarily imply the fluid flowing within it, but rather that the fluid can be transported or can flow through it.</p>

As used herein, the term 'electromagnetic radiation

<p>15th To radio waves, microwave radiation, infrared and near infrared radiation</p>

Infrared, visible light, ultraviolet light, X-ray radiation, and gamma radiation.

As used herein, the term "optical computing device" refers to an optical device configured to receive the input of electromagnetic radiation associated with a fluid and produce an output of electromagnetic radiation from an element

<p>20 Processing a topic within the optical computing medium. The processing element can be, for example, an integrated computational element (ICE), also known as a multivariate optical element (MOE), used in an optical computational medium. The processing element to be readable by a detector, so that the detector output can be linked</p>

<p>25 By a characteristic of the fluid, such as the type and concentration of a gas in the fluid. Electromagnetic radiation output can be</p>

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Of the treatment component are reflected electromagnetic radiation, transmitted electromagnetic radiation, and/or scattered electromagnetic radiation. It can be assumed that the detector analyzes the reflected, transmitted, or scattered electromagnetic radiation by the structural variables of the optical computing device in addition to other considerations known to those skilled in the field. Besides, the emission and/or scattering can also be monitored

<p>5 Fluid, eg via fluorescence, fluorescence, scattering of Mie, Raman, and/or Raleigh, by optical computational means.</p>

As used herein, the term “photoreaction” or its variants refers to the reflection, transmission, scattering, diffraction, or absorption of electromagnetic radiation either on, through, or from one or more processing elements (ie, embedded computer elements or optical elements). multivariate), fluid, or

<p>10 A gas present in the fluid. Thus, photoreacted light refers to electromagnetic radiation that is reflected, transmitted, scattered, deflected, or absorbed by, emitted, or reradiated, for example, using a treatment element, but may also be used to interact with a fluid or gas trapped in the fluid.</p>

The systems and demonstration methods described herein will include at least one optical computational medium

<p>15th Placed along or in a flow path that no fluid is observed in it. Each optical computational device may include an electromagnetic radiation source, at least one processing element (for example, an integrated computing element), and at least one detector set up to receive photoreactive light from at least one process element or fluid. In some embodiments, it may be configured Illustrative optical computational means specifically to detect, analyze, and quantitatively measure a specific property</p>

<p>20 of a fluid, such as the type and concentration of a gas present in the fluid. In other embodiments, the optical computer aids may be general-purpose optical aids, with post-processing used (eg, by computer aids) to specifically detect a fluid property.</p>

The optical computational methods currently described can perform real-time or near-real-time computations (analytics) without the need for time-consuming sample processing.

<p>25 Optical computational aids specifically designed to detect and analyze specific properties of a fluid or a fluid </p>

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A gas present in the fluid. As a result, the interfering signals are distinguished from those of interest in the fluid by an appropriate modulation of the optical computations, such that the optical computations provide a rapid response regarding fluid properties based on the detected output. In some embodiments, the disclosed output may be converted to a voltage distinct from the capacitance

<p>5 fluid property.</p>

Optical computer aids can be configured not only to reveal the composition and concentration of gases in the fluid, but also to determine the physical and other properties of the fluid and/or gas based on the analysis of the electromagnetic radiation received from the fluid and/or gas. For example, optical computational aids can be configured to determine the concentration of a degradation product and to cross-correlate the specified concentration with a characteristic.

<p>10 Fluid. As will be realized, optical computational aids can be configured to detect various properties (eg, gas compounds and their related concentration) of the fluid as needed. All of the above is required to carry out the monitoring of the properties which requires the inclusion of appropriate processing and detection means. In the optical computational medium for each characteristic In some embodiments, the properties of the fluid may be a combination of the properties of the dissolution products contained therein (eg,</p>

<p>15th Linear, non-linear, logarithmic, and/or exponential combination). Accordingly, the more properties and dissolution products that are detected and analyzed using optical computational means, the more accurate the properties of the specific fluid and/or gas will be detected.</p>

The optical computational methods described here use electromagnetic radiation to perform the calculations, in contrast to the wired circuits of conventional electronic processors. When radiation interacts

<p>20 Electromagnetic With a fluid, unique physical and chemical information relating to the fluid is encoded in electromagnetic radiation reflected from, transmitted through, or radiated through the fluid. This information is usually referred to as the spectral "fingerprint" of the fluid. The optical computational means described herein are to extract the spectral signature information of various properties or dissolution products present in a fluid, and to convert this information into a detectable output related to one or more properties of the fluid or gas.</p>

<p>25 present in the fluid. This means that with appropriate settings for optical computational devices, it is possible to</p>

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Separate the electromagnetic radiation associated with a characteristic or decomposition product of interest of a fluid from the electromagnetic radiation associated with all other components of the fluid for the purpose of estimating the fluid's properties in real or near real time.

The processing elements used in the described optical computational aids can be distinguished

<p>5 Here as Computational Embedded Elements (ICE). Each ICE is able to distinguish electromagnetic radiation associated with the property of interest from electromagnetic radiation associated with other components of the fluid. Referring to Figure 1, an illustrative ICE 100 suitable for use in optical computational aids used in systems and methods is shown. Described here.As shown, ICE 100 can include a combination of 102 and 104 alternating layers, such as silicon</p>

<p>10 (Si) and SiO2 (quartz), respectively. In general, these 102, 104 layers consist of</p>

Substances whose refractive index is high and low, respectively. Other examples may include niobia, niobium, germanium and germanium, SiO, MgF, and other high and low modulus materials known in the art. Layers 102, 104 may be strategically placed on a photolithic substrate 106. In some embodiments, the photolithic substrate 106 is a BK 7-type photonic glass. in a

<p>15th Other embodiments, the photonic substrate can be 106 other types of photonic substrate, such as quartz, sapphire, silicon, germanium, zinc selenide, zinc sulfide, or various plastics such as polycarbonate, polymethylmethacrylate, (polyPMMA) Polyvinylchloride (PVC), diamonds, ceramic materials, combinations thereof, and the like.</p>

<p>20 At the opposite end (for example, against the photonic substrate 106 in Figure 1), an ICE 100 can include a layer 108 generally exposed to the environment of the facility or facility. The number of layers 102, 104 and the thickness of each layer 102, 104 are specified by the spectral features that are Obtained from fluid characteristic spectroscopy using a conventional spectroscopic instrument The spectrum of interest for a specific characteristic typically includes any number of different wavelengths It should be recognized that 100 ICE</p>

<p>25 The illustration in Figure 1 does not actually represent any specific property of a fluid, but rather is provided </p>

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Just for clarification. Thus, the number of layers 102, 104 and their thickness values, as shown in Figure 1 are not related to any specific property. The scale and thickness values ​​do not necessarily apply to layers 102 and 104, and therefore should not be constrained by the current disclosure. Moreover, those skilled in the field will easily realize the possibility of variety of materials

<p>5 which constitute each layer 102, 104 (i.e., Si and SiO2), depending on use, cost of materials, and/or applicability of the material to the given fluid.</p>

In some embodiments, the material of each layer 102, 104 may be doped or two or more materials may be combined in some way to achieve the preferred optical property. In addition to solids, the illustrative ICE 100 may also contain liquids and/or gases, optionally in combination with materials

<p>10 solid, to produce a preferred optical property. In the case of gases and liquids, the ICE 100 may have a corresponding vessel (not shown) surrounding the gases or liquids. The illustrative miscellaneous images of the ICE 100 also include stereo light elements, clamps, piezoelectrics, light pipe, and digital light pipe (DLP), and/or acoustic optical elements, for example that can create transmission, reflection, and/or absorption properties of interest.</p>

<p>15th Multiple layers of 102,104 show different refractive indexes. Through the appropriate selection of materials</p>

Layers 102, 104 and their relative distance and thickness, 100 ICE can be configured to selectively pass/reflection/reflect preset portions of light to electromagnetic radiation at different wavelengths. A predetermined weighting or loading factor is assigned to each wavelength. The thickness and distance of layers 102 and 104 can be determined using a variety of methods for approximation from a spectrogram

<p>20 The property or decomposition product of interest. These methods can include an inverse Fourier transform (IFT) of the optical transmission spectrum and create 100 ICEs as a physical representation of the IFT. Transform the IFT approximations into a structure based on materials with known constant refractive indexes.</p>

The values ​​applied by layers 102, 104 for 100 ICE at each wavelength are set to the 25 regression values ​​described for a known equation, data, or spectral significance. In short, can initialize

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100 ICE to perform the numerical product of the input light beam at 100 ICE and a preferred loaded regression vector expressed at each layer 102, 104 for each wavelength. As a result, the intensity of the outgoing light for 100 ICE is related to the characteristic or degradation product of interest.

Referring now to Figure 2, an illustrative optical computer aid 200 is shown for a fluid monitor 202,

<p>5 According to one or more embodiments. In the embodiment shown, fluid 202 may be included or</p>

Otherwise flow in a illustrative flow path 204. Flow path 204 can be a flowline, pipeline, a wellbore, an annular space defined in a wellbore, or any flowlines or pipelines extending to/from a wellbore. Fluid 202 in the flow path 204 may be flowing in the general direction indicated by arrows a (that is, from the upstream to the post direction).

<p>10 Flow path 204 largely vertical, largely horizontal, or any directional shape in between, without</p>

Keep away from the detection field.

The optical computer instrument 200 may be configured to determine a property of interest in fluid 202, such as the type and/or concentration of a gas present in fluid 202. In some embodiments, the instrument 200 may include an electromagnetic radiation source 208 configured to emit or otherwise generate radiation

15th Electromagnetic 210. The source of electromagnetic radiation 208 may be any means capable of emitting or producing electromagnetic radiation. For example, the source of electromagnetic radiation 208 may be a light lamp, light emitting diode (LED), laser, dark body, photonic crystal, X-ray source, combinations thereof, or the like. In some embodiments. , the 212 lens can be configured to collect or otherwise receive radiation

20 Electromagnetic 210 and directing a beam of 214 electromagnetic radiation 210 toward the fluid 202. A lens 212 can be any optical medium configured to transmit or otherwise transmit electromagnetic radiation 210 as needed, such as a normal lens, Fresnel lens, diffraction light element, stereoscopic graphic element, mirror (for example, a focusing mirror), or a type of beam guide. In other embodiments, the lens 212 can be removed from the 200 medium and the radiation can instead be directed

25 electromagnetic radiation 210 towards fluid 202 directly from the source of electromagnetic radiation 208.

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In one or more embodiments, the medium 200 may also include a sampling window 216 that is placed near or otherwise in contact with the fluid 202 for detection purposes. The sampling window 216 can be made of a solid or semi-solid array which is configured to allow electromagnetic radiation 210 to be transmitted through it. For example, a window can be made

<p>5 Sampling 216 of, but not limited to, types of glass, types of plastics, semiconductors, crystalline materials, polycrystalline materials, hot or cold pressed powders , combinations thereof, or the like. After passing through the sampling window 216, the electromagnetic radiation 210 collides with and photoreacts with fluid 202. As a result, the photoreactive radiation 210 is generated by and reflected from fluid 202. Those skilled in the art will readily realize, however, that the variety</p>

<p>10 An alternative to the 200 method could allow the generation of photoreactive radiation 218 by scattering it, scattering it,</p>

diffracted, absorbed, emitted, or re-radiated by and/or from fluid 202, without departing from the detection field.

The photoreactive radiation 218 resulting from the interaction with fluid 202 can be directed to or otherwise received by an ICE 220 placed in the medium 200. ICE 220 can be a component

<p>15th spectrally broadly similar to the 100 ICE described above with reference to Fig. 1. Accordingly, when</p>

Operation An ICE 220 can be configured to receive photoreactive electromagnetic radiation 218 and produce modulated electromagnetic radiation 222 corresponding to a specific fluid characteristic 202. Specifically, modulated EMR 222 is photoreactive electromagnetic radiation with ICE 220, for which an approximation of the regression vector corresponding to fluid characteristic 202 is obtained. .

<p>20 While Figure 2 depicts that 220 ICE receives electromagnetic radiation reflected from fluid 202, an ICE 220 can be located at any point along the optical chain of the medium 200, without departing from the detection field. For example, in one or more embodiments, an ICE 220 (shown by dashed lines) can be placed in the optical chain before the sampling window 216 and substantially the same results are equally obtained. In other embodiments, it can be</p>

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That the 220 ICE produces the electromagnetic radiation modulated 222 through reflection, rather than through it.

Furthermore, although only one ICE 220 is illustrated in the medium 200, embodiments are shown here that involve the use of at least two ICE components in the medium 200 adapted to determine

<p>5 Cooperatively the property of interest in fluid 202. For example, two or more ICEs may be placed in series or in parallel in medium 200 and configured to receive photo-interacting radiation 218 and thus the sensitivity values ​​and detector limits of the medium 200 are optimized. In other embodiments, it is possible to Placement of two or more ICEs on a movable assembly, such as a rotating disk or an oscillating linear array, which moves so that the individual ICE components are capable of exposure 10 to, or otherwise react optically with electromagnetic radiation for a specified short period of time. Could</p>

Two or more ICE components of any of these embodiments are configured to either be bound or separated from the property of interest in fluid 202. In other embodiments, two or more ICEs may be configured to be mutually associated positively or negatively with the property of interest in fluid 202.

In some embodiments, it may be required to monitor more than one characteristic of interest at a time

<p>15th Use of the medium 200, such as the detection of multiple types or compounds of gases present in fluid 202. In these embodiments, different configurations of several ICE components may be used, with each ICE component being configured to reveal a specific and/or characteristic of interest. In some embodiments, the characteristic can be analyzed sequentially using several ICE components which are provided as a single beam of electromagnetic radiation reflected from or permeating through fluid 202. In some</p>

<p>20 In embodiments, many ICE components can be placed on a rotating disk, whereby single ICE components are exposed only to a beam of electromagnetic radiation for a short time. Advantages of this method can include the ability to analyze many properties of fluid 202 using a single optical computer 200 and provide the opportunity to test additional properties (for example, types or compounds of gases present in fluid 202) simply by adding additional ICE components to the turntable. .</p>

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In other embodiments, several optical computational devices may be located at a single location along the flow path 204, each of which contains a unique ICE configured to detect a specific property of interest in fluid 202. In these embodiments, a beam splitter may shift a portion of Electromagnetic radiation reflected by, emitted from, or transmitted through fluid 202 and into each 5 optical computer medium. Each optical computational device can, in turn, be coupled to a detector or array

A corresponding detector configured for the detection and analysis of electromagnetic radiation output from a related optical computational medium. Parallel modulations of optical computing devices can be particularly useful for applications that require low power inputs and/or non-moving parts.

Those skilled in the art will realize that any of the previous decks can also be used in combination with 10 combinations of decks in any of the current incarnations. For example, you can put two

of optical computing devices having a turntable with a set of ICE components placed on it in series to perform analysis at a specific location along the length of the flow path 204. Similarly, multiple detection stations, each containing optical computing devices, can be set up in parallel, respectively for a similar analysis.

<p>15th The modulated electromagnetic radiation 222 that was produced by the ICE 220 could then be transmitted to the detector 224 to quantify the signal. Detector 224 can be any detector capable of detecting electromagnetic radiation, and can generally be distinguished as a phototransformer. In some embodiments, the detector 224 may be, but is not limited to, a thermal detector such as a thermopile or photoacoustic detector, a semi-detector</p>

<p>20 semiconductor detector, piezo-electric detector</p>

charge coupled device (CCD) detector, visual or matrix detector, split detector, photon detector (such as a photomultiplier tube), photodiodes, combinations thereof, or the like, or other detectors known to those skilled in the art.

In some embodiments, the detector 224 can be configured to produce an output signal 226 in real time or

<p>25 near real time in the form of voltage (or current) similar to the specific characteristic of interest in</p>

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Fluid 202. The voltage returned by detector 224 is essentially the numerical product of the photoreaction of photoreactive radiation 218 with the relevant ICE 220 as a function of the concentration of the characteristic of interest for fluid 202. As such, the output signal 226 produced by the detector 224 and the concentration of The correlated property, for example, is proportional. In the other 5 embodiments, however, the relationship can be corresponding to a polynomial function, an exponential function, a logarithmic function,

and/or a combination thereof.

In some embodiments, the device 200 may include a second detector 228, which may be identical to the first detector 224 in that it may be any device capable of detecting electromagnetic radiation. The second detector 228 can be used to detect radioactive drifts 10 caused by electromagnetic radiation source 208. Unnatural radioactive drifts can occur

Desirable electromagnetic radiation intensity 210 is due to a wide range of causes that are likely to cause negative effects on the medium 200. These negative effects can be particularly harmful to measurements obtained over a period of time. In some embodiments, radiative aberrations can occur as a result of the accumulation of a film or material on the sampling window 216 15 which has the effect of reducing the quantity and quality of light that ultimately reaches the first detector 224.

Without proper compensation, these radiative aberrations can result in misreadings and the output signal 226 will not be fundamentally or precisely related to the characteristic of interest.

To compensate for these types of undesirable effects, the second detector 228 can be configured to generate a compensating signal 230 that is generally indicative of the radiative aberrations of the electromagnetic radiation source 20 208, and thus the output signal 226 generated by the first detector 224 is measured.

As shown, the second detector 228 can be configured to receive a portion of the photoreactive radiation 218 through the beam splitter 232 to detect radioactive aberrations. In other embodiments, however, a second detector 228 may be positioned to receive electromagnetic radiation from any part of the optical chain in the medium 200 to detect radiation aberrations, without departing from the detection field.

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In some applications, the output signal 226 and the compensating signal 230 can be transmitted to or otherwise received by a signal processor 234 that is coupled in connection with both detectors 224 and 228. The signal processor 234 can be a computer with a processor and a computer-readable storage medium in it. Instructions stored on it, which, when executed by the 234 processor, cause the

<p>5 Optical Computing Mode 200 performs a number of operations, such as identifying a property of interest for fluid 202. For example, the concentration of each characteristic detected using Optical Computing 200 can be fed into an algorithm that is run by the signal processor 234. The algorithm can be part of networks An artificial neuron adapted to use the concentration of each of the detected property to evaluate the property(s) as a whole or fluid quality 202.</p>

<p>10 The signal processor 234 can also be configured to combine the compensating signal 230 with the output signal 226 by computing the measurement of the output signal 226 in light of any of the radiative aberrations detected by the second detector 228. Combining the output and compensating signals 226, 230 can require calculating the ratio of the two signals 226. , 230. For example, the concentration or amplitude of each characteristic determined using the optical computer 200 can be fed into an algorithm operated by the signal processor</p>

<p>15th 234. The algorithm can be configured to make predictions about how the properties of the fluid will change 202 if the concentration of the fluid changes</p>

One or more components or additives relative to each other.

In real time or near real time, the signal processor 234 can be configured to provide an output signal 236 corresponding to the characteristic of interest in fluid 202, such as a gas concentration present in fluid 202. The resulting output signal 236 can be read by the operator who can take the results

<p>20 take into account and make appropriate adjustments or take appropriate action, if necessary. In some embodiments, the output of the resulting signal 236 can be transmitted, either wired or wirelessly, to the operator for consideration. In other embodiments, the resulting output signal 236 may be marked by the signal processor 234 as being within or outside a predetermined or preprogrammed range for appropriate operation and can inform the operator of an out-of-range reading so that appropriate corrective action is taken, or otherwise</p>

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It takes a self-corrective action so that the output signal 236 returns to a value that is within the pre-set or pre-programmed range for proper operation.

Referring now to Fig. 3, another 300 illustrative optical computer aids are shown for the fluid monitor 202, according to one or more embodiments. The computer method can be similar

<p>5 Optical 300 is in some respects with the computational optical instrument 200 given in Fig. 2, and can therefore be better understood by reference to it, as similar numbers refer to similar items that will not be described again. Again, the optical computer medium 300 can be configured to determine the concentration of a property of interest in fluid 202, such as the concentration of a gas in fluid 202, as being included in the flow path 204. Unlike the medium 200 in Figure 2, however, the medium can be configured</p>

<p>10 The optical computer 300 in Fig. 3 transmits electromagnetic radiation 210 through fluid 202 through a first sampling window 302a and a second sampling window 302b positioned radially against the first sampling window 302a on the flow path 204. The first and second sampling windows can be 302a. , b is identical to the sampling window 216 described above in Fig. 2 and therefore will not be described again.</p>

<p>15th When electromagnetic radiation 210 passes through fluid 202 through the first and second sampling windows 302a,b, it photoreacts with fluid 202 and then the photoreactive radiation 218 is directed to, or otherwise received by, ICE 220 placed in medium 300. It is also noted that, While Figure 3 depicts an ICE 220 receiving the photoreactive radiation 218 that passes through the sampling windows 302a,b, the 220 ICE can be equally placed at any</p>

<p>20 A point along the optical chain of the medium 300, without moving away from the detection field. For example, in one or more embodiments, 220 ICE can be placed in the optical chain prior to a first sampling window 302a and obtain substantially the same results. Also in other embodiments, the ICE 220 can produce the EMR 222 by reflecting, rather than through it. Furthermore, similarly to the 200 method in</p>

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In Figure 2, embodiments involving the use of at least two ICE components in medium 300 adapted to cooperatively determine the property of interest in fluid 202 are shown here.

The modulated electromagnetic radiation 222 produced by the 220 ICE is then transmitted to the detector 224 to quantify the signal and generate the output signal 226 corresponding to the specified characteristic being replaced.

<p>5 Interest in the fluid 202. The medium 300 may also include a second detector 228 to detect radioactive aberrations from an electromagnetic radiation source 208. As shown, a second detector 228 can be configured to receive a portion of the photoreactive radiation 218 through the beam splitter 232 to detect aberrations radiological; Then the output signal 226 and the compensating signal 230 can be transmitted to or otherwise received by the signal processor 234 which can computationally</p>

<p>10 Combine signals 230 and 226 and provide in time or near real time the resulting output signal 236 corresponding to the concentration of the property of interest in fluid 202.</p>

Those skilled in the art will readily understand the many different applications that it can conveniently use with optical computing devices 200, 300, and their many alternative configurations.

The systems and methods described herein use at least one optical computational method in combination with

<p>15th At least one gas analysis method to more accurately measure the gas composition of the drilling fluid than at multiple points in the drilling fluid circulation system. Turkish gas analysis methods measure the gases of all the gases of interest in the gas extracted from the drilling fluid, and the optical computer methods measure the concentration of only some of the gases of interest. A correction factor can be derived from comparing the measurements of two types of means. Depending on the configuration of the system, the correction factor can be a correction factor</p>

<p>20 Single point, double point correction factor, or point to point correction factor.</p>

Figure 4 presents an illustrative representation of a part of System 400 suitable for deriving a one-point correction factor for the gas-fluid composition. The fluid in a gas discharge device 410 flows through a feed line 412. The gas discharge device 410 extracts at least a portion of the gas retained in the fluid. At least part of the extracted gas can then be transferred to at least one gas analyzer 414 via a line

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Feed 416. Gas analyzers 414 can analyze the composition of the extracted gas for the concentration of the gases of interest and the total gas quantity. At least one optical computer device 418 can be placed in System 400 before the gas-discharge device 410 and configured to measure the concentration of a reference compound and a gas of composition (eg, methane or ethane). The reference compound can be

<p>5 A volatile compound introduced into the fluid (eg, fluorinated hydrocarbons), inherent in the fluid (eg, CO2), or a spectrally interfering gas (eg, ethane interfering with methane or ethane interfering with ethane). That both the gas analyzer 414 and the optical computer 418 produce output signals 420 and 422, respectively, corresponding to a measurement taken.Output signals 420, 422 are received</p>

<p>10 by a signal processor 424 that is intimately coupled to gas analyzers 414 and optical computing devices 418.</p>

The signal processor 424 can be identical to the signal processor 234 in Figures 2 and 3 and can be configured to receive and process output signals 420, 422. Specifically, the signal processor 424 can use a configured algorithm to calculate or otherwise determine the concentration of the detected gases.

<p>15th Using the gas analysis method 414, calculate a correction factor, apply the correction factor to the output signals 422 of the optical computer 418 to calculate the gas concentration detected by the optical computer 418, and derive the concentration of all the gases of interest in the drilling fluid.</p>

For example, optical computer aids 418 can be configured to measure the concentration of methane in drilling fluid 20 (CH20).₄] _DF[ “(The concentration of the reference compound in the drilling fluid)” ref]_DFGas Analyzers 414 can be configured to measure the concentration of methane in the extracted gas (“CH4”)._E[G]”), the concentration of the reference compound in the extracted gas (“ref]_E[G]”), and the concentration of one or more gases of interest in the extracted gas_EG]”). A one-point correction factor can be determined by comparing CH .₄]_DF/[CH₄]_EG] and ref]_DF/[ref]_EG] or variations in CH₄]_DF/[CH₄]_EG] and ref]_DF/[ref]_EG].

<p>25 Comparison of concentrations in drilling fluids and extracted gas can include collection processes or other methods </p>

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To determine the reaction agents of other components. When the spectral response of the reference gas contains peaks within the spectral response of an interfering gas, peak curves can be used to determine the interference at the measurement point. The interference intensity can then be removed before the correction factor is determined. After determining the correction factor, the graph can be used to apply each correction factor to each gas]_EG] and infer concentration

<p>5 All gases of interest in the drilling fluid.</p>

Figure 5 presents an illustrative representation of a part of System 500 suitable for deriving a double-point correction factor for the gas-fluid composition. The fluid in a gas discharge device 510 flows through a feed line 512. The gas discharge device 510 extracts at least a portion of the gas retained in the fluid. At least a portion of the extracted gas can then be transferred to at least one gas analyzer 514 via a line

<p>10 Feed 516. Gas analyzers 514 can analyze the composition of the extracted gas for the concentration of the gases of interest and the total gas quantity. At least one optical computer device 518 can be placed in System 500 before the gas-discharge device 510 and configured to measure the concentration of a reference compound and a gas of the formation. At least one optical computer device 520 in System 500 may be placed between the gas discharge device 510 and the gas decomposition device 514 and configured to measure the concentration of the reference compound</p>

<p>15th The gas from the configuration. Both the gas analyzers 514 and the optical computational devices 518, 520 can produce output signals 522, 524, and 526, respectively, corresponding to a measurement taken. The output signals 522, 524, 526 are received by a signal processor 528 that is coupled in connection with gas analyzers 514 and optical computing devices 518, 520.</p>

Double-point calibration can be characteristically capable of correcting a non-linear background in

<p>20 measurements, which may be contributed by a compound having an overlapping spectrum.</p>

In some cases, the above titration methods may use more than one reference compound. In some cases, it is not possible to use a reference gas by developing a direct relationship between a calibration curve for the optical computer measurements and the gas analysis instrument, which is referred to here as a point-to-point calibration.

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In any of the foregoing calibration arrangements and methods, the calibration may be carried out continuously in some embodiments. Alternatively, in some cases, calibration may be performed periodically (for example, once every 15 minutes, once every hour, and so on). In addition, in some cases, calibration may be performed on demand (for example, when . Launched by the operator

<p>5 So is the accuracy of the systems and methods described herein for measuring the gas content and gas composition of a drilling fluid in real time.</p>

In the examples shown for calibrations, optical computer aids are deployed near the gas-discharge facility. However, additional optical computational devices can be deployed at multiple points within the drilling fluid circulation system to monitor the drilling fluid and associated gas content using calibrations for each

<p>10 A type of optical computational medium determined using one of the methods/systems described above or similar. Depending on the location of the specific optical computer, different types of fluid information can be obtained. In some cases, for example, optical computational means can be used to monitor the type and concentration of gases present in it before and after the drilling fluid has been circulated in and out of the borehole. In other cases, optical computer aids can be used to analyze the gas sample</p>

<p>15th Extracted in real time after extraction from the drilling fluid by a conventional drilling fluid sampling process. In other cases, optical computational means of drilling fluid monitoring at or near the borehole choke facility may be used to record the real-time gas concentration of the drilling fluid as the drilling fluid circulates under wellbore conditions.</p>

For example, now referring to Figure 6, an illustrative 600 . borehole drilling assembly is shown

<p>20 One or more optical computational means may be used as described herein to monitor a drilling fluid or a completion fluid, according to one or more embodiments. The drilling assembly may include 600 drilling rigs 602 supporting a 604 jack with a movable block 606 to raise and lower the 608 drill string. The 610 drill stem holds the 608 drill string when lowered via a rotating table 612. The 614 drill bit is attached to the far end of the tubing string Drill 608 and are either driven by a down motor</p>

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borehole and/or via du arne series 608 drill pipes from the surface of the borehole. When the 614 drill bit rotates, it creates a 616 drill hole that penetrates several 618 core formations.

Pump 620 (for example, a mud pump) administers drilling fluid 622 through a feed pipe 624 drill stem 610, which transfers drilling fluid 622 down the well through the inlet raceway specified in

<p>5 Drill Series 608 and through one or more of the nozzles in the drill bit 614. The drilling fluid 622 is then circulated and returned to the surface through an annular space 626 marked between the 608 thread and the 616 drill hole Warren found. The drilling fluid 622 provides hydrostatic pressure to block formation fluids. from entering the 616 drilling hole and keeping the 614 drill bit cool and clean while drilling. Drilling fluid 622 also carries drilling extracts and solids out of the drill hole 616 and is suspended</p>

<p>10 Drilling extractors and solids while drilling pauses and/or when the drill bit 614 is inserted into and out of the drill hole 616.</p>

As spent drilling fluid 622 returns to the surface, it can exit the annular space 626 at the borehole 627 and subsequently pass through one or more of the valves or choke valves 628 (one is shown) through an interconnected flow line 630. throttle valve

<p>15th 628 to maintain or otherwise regulate the pressure on the annular space 626 off the surface, for example</p>

The example is in the range of about 100 psi to 1500 psi. As a result, this will allow drilling to continue below the equilibrium level and be useful in reducing formation damage, but also facilitating an increase in drilling speed. It will be recognized, however, that the choke valve(s) 628 may be dispensed with in other embodiments and that the spent drilling fluid 622 may return

<p>20 Alternatively to the surface at atmospheric pressures, without moving away from the detection field.</p>

Throttle valve 628, Spent drilling fluid 622 may be transferred to one or more drilling fluid qualification facilities via the interconnected flowline 630. These drilling fluid qualification facilities may include, but are not limited to, one or more 632 gas degassing units and control equipment in solids 634 (eg, vibrators). The gas discharge unit 632 can be any

<p>25 A device or prepared for the separation from the drilling fluid 622 Gases (i.e., hydrocarbon and non-hydrocarbon types). </p>

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(hydrocarbon) which may be retained in the drilling fluid 622 while circulating in and out of the drilling hole 616. Solids control equipment 634 can be configured to largely remove drilling extracts and solids from drilling fluid 622 and deposit “clean” drilling fluid 622 into a holding hole Adjacent 636 (that is, a mud pit).

<p>5 Various additives or components may be added to the drilling fluid 622 to keep the drilling fluid 622 in proper operating order and otherwise improve drilling performance. In some embodiments, additives and materials may be added to the drilling fluid 622 via a mixing hopper 638 coupled through the fluid to a holding hole 636. Demonstrative components that may be added to the drilling fluid 622 include, but are not limited to, emulsions, weights, viscosities, Thickeners, Flow Rates, Materials</p>

<p>10 Diluents, flocculants, anionic polyelectrolytes (eg, acrylates, polyphosphates, lignosulfonates, tannic acid derivates, and so on), high-temperature polymers, baby stabilizers, bitumen, baby water inhibitors, treatments and other base fluids, combinations thereof, etc. Qualified drilling fluid 622 can then be recycled and pumped once</p>

<p>15th Others are inside the drill hole 616 using the pump 620 through the feed tube 624.</p>

In accordance with the present disclosure, gas analysis may be done by recording the mud performance of drilling fluid 622 using optical computer aids 640 and photocomputer media 650 using photocomputer media 640 calibrations according to or similar to the methods and configurations described in Figures 4-5. The gas analyzer 650 receives gas from the gas discharge unit 632 through flow line 652.

<p>20 Depending on the analysis method, optical computer aids can be placed in many locations within the . system</p>

Rotate the drilling assembly 600. For example, as shown in Figure 6, optical computer aids 640A, 640B, 640C, 640D, and 640E can be located along flush pipe 624, along flowline 630 between throttle valve 628 and gas discharge unit 632, along Flow line 630 before the choke valve 628, along the flow line 652 between the gas discharge unit 632

<p>25 And the gas analyzer 650, with the flow line 630 running between the gas discharge unit 632 and the control equipment</p>

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at 634 solids, respectively. The optical computational aids 640a-e may be substantially similar to at least one of the optical computational aids 200 and 300 presented in Figs 2 and 3, respectively, and thus will not be described in detail again. In an illustrative process, the optical computer aids 640a-e can be configured to measure and record properties of the drilling fluid in real time 622, such as the type and/or concentration of one or more gases present in it at the monitoring sites.

its own concerned.

In one or more embodiments, the optical computing device 640a-e may be intimately coupled to a signal processor 642 and configured to transmit corresponding output signals 644a-e, respectively, to signal processor 642. The signal processor 642 may be analogous to the signal processor 234 contained in

<p>10 Figures 2 and 3 can be configured to receive and process 644a-e output signals. Specifically, the signal processor can use 642 configured algorithms to calculate or otherwise determine the concentration or type of gas detected at each monitored location. The signal processor 642 can also be configured to determine the differences between any two or more of the 640a-e output signals. In other words, the signal processor 642 can be configured to determine how the gas concentration and/or amplitude of the property of interest in fluid 622 varies between each location.</p>

<p>15th m neck.</p>

Furthermore, the signal processor 642 can be configured to receive 654 output signals from the gas analyzers 650, so that a comparative analysis is performed between the gas concentrations measured by the gas analyzers 650 and the single optical computer 640a-e (described in detail here). Real-time or near-real-time, the signal processor 642 can be configured to provide an output signal of 646 analog

<p>20 For the concentration of single gases or the total gas, each can be measured or derived as described in detail here.</p>

In some embodiments, the resulting output signal 646 may be transmitted, either wired or wirelessly, to one or more of the paired 648 terminals in connection with the signal processor 642. Peripherals 648 may include, but are not limited to, a mobile device, a computer monitor, or a paired printer machine

<p>25 with a computer. In some embodiments, the 648 terminal can be configured to provide one or more</p>

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Graphical outputs such as a Pixler diagram, Haworth diagram, or gas ratio diagram, depicting many of the properties, variables, and property(s) detected in fluid 622 (for example, the concentration of single gases or total gas in the drilling fluid). The well operator can then be able to consult and interpret the graphical output and thus make intelligent decisions 5 about how to best manage the well in response.

10

15

In other embodiments, terminal devices may include 648 audible or visual alarm mechanisms or devices that can be triggered. For example, one or more output signals 644a-e, 654 may be identified or analyzed by the signal processor 642 as being in or out of a predetermined or preprogrammed range for proper operation of the drilling fluid 622. If the output signals 644a-e, 654 or analyzed exceed a pre-determined or pre-programmed operating range, the resulting output signal 646 can sound an alarm that constitutes the terminal 648 and the alarm can be configured to notify the operator to take appropriate corrective action on the drilling fluid 622. In some embodiments, the signal processor 642 can be configured to automatically take an appropriate corrective action so that the resulting output signal produces 646 values ​​that fall within the predefined range or preprogrammed for proper operation. For example, the signal processor 642 could be intimately associated with an automated control system (not shown) which could be configured to take the required corrective action.

As shown, the Optical Computing Method 640b and Gas Analyzer 650 can be configured and operate similarly to the Optical Computer 418 and Gas Analyzer 415 in Figure 4 to provide a single-point calibration that can be applied to other optical media.

<p>20 are set in System 600. Furthermore, the Optical Computing 640b, 640d, and Gas Analyzer 650 can be configured and operate similarly to the Optical Computing 518, 520 and Gas Analyzer 514 presented in Figure 5 to provide a double-point calibration that can be applied to an optical computer. Others are placed in order 600.</p>

In some embodiments, the gas concentration measured from the optical computer 640 AH can be compared

25 placed along the flow line 630 after the gas discharge device 632 with the gas concentration obtained

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It is obtained from the optical computer device 640b placed before the gas degassing device to provide efficient degassing.

In some embodiments, a first optical computer device 640a may be placed to monitor the introduction of drilling fluid 622 into the drilling hole 616, and a second optical computer device 640b may be placed to monitor the drilling fluid entry

<p>5 622 after it is returned to the surface and is otherwise decompressed via the throttle valve 628. At</p>

More specifically, the first optical computer 640a may be located in the feed tube 624 leading to a winch 604 from pump 620 (or otherwise from any fluid-connected location after pump 620 and before the drilling hole 616), and the second optical computer may be located 640b on or otherwise combined with flowline 630 before the gas degassing unit 632 (eg.

<p>10 For example, near the entrance to the gas discharge unit 632). As it will be realized, more than one optical computer can be located at each of the mentioned monitoring sites, without moving away from the detection field.</p>

The first output signal 644a can indicate the type/concentration of the gas in the drilling fluid 622 or other characteristic of the fluid 622 when drilling fluid 622 enters the drilling hole 616. Similarly, the second output signal 644b can indicate the type/concentration of the gas or a characteristic Other fluid 622 when removing

Pressure from drilling fluid 622 exiting the drilling hole 616. The signal processor 642 can receive output signals 644a,b in real time and provide the resulting output signal 646 that the operator can take into account by one or more peripheral means 648, at as described above. In some embodiments, the resulting output signal 646 can notify the

<p>20 Operating with gas type/concentration in drilling fluid 622 when drilling fluid 622 enters drilling hole 616, according to first output signal 644a. In other embodiments, the resulting output signal 646 can notify the operator of the type/concentration of gas in drilling fluid 622 when drilling fluid 622 exits the drilling hole 616, according to the second output signal 644b. As a result, the operator can be able to perform gas analyzes by recording the mud performance of drilling fluid 622 without the need for</p>

<p>25 Extraction of the gas sample from the 622 return drilling fluid.</p>

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Also in other embodiments, the signal processor 642 can be configured to make a comparison between the first and second output signals 644a,b, thus providing the operator with an output signal 646 via terminal aids 648 detailing the differences between the two output signals 644a,b. As such, the operator can be informed of the quantity and concentration of one or more gases that may have

<p>5 entered or otherwise retained in drilling fluid 622 while circulating in the drilling hole 616. This data can be useful to provide information on the hydrocarbon content of the rocks being drilled through and, as a result, the operator can decide to adjust one or more of the variables I decided to dig or complete in response to it.</p>

For example, in some embodiments, the resulting output signal 646 can notify the mast

<p>10 To operate in the presence of a specified type or quantity of a preferred gas in a specified layer or area of ​​the aquifer 618 during drilling. As a result, at least one drilling variable can be tuned in response to it, such as changing the ground orientation of the drill bit 614 so that the drill hole 616 can be drilled or largely shaped in said layer or area. In some embodiments, the preferred gas may be one or more hydrocarbons which may be produced for processing. In other embodiments, with</p>

<p>15th Therefore, the gas of choice could be helium. Those skilled in the art will recognize the amount of excess helium returning to the surface and trapped in drilling fluid 622 could be indicative of high porosity in Formation 618, and high porosity could indicate an area capable of high production rates. When said gases and hydrocarbons are detected, the operator may change the ground direction of the well path so that the drilling hole remains in said layer to a large extent,</p>

<p>20 Accordingly, the production and potential efficiency rates of hydrocarbons are increased.</p>

As it will be realized, this can prove particularly effective in skewed or horizontal wells where the change of ground orientation can cause the well trajectory to be kept largely parallel and otherwise within a hydrocarbon-containing stratum or zone. This can also prove effective, however, in moored wells where the well operator is able to record an area of

<p>25 An RC drilling hole 616 is in which a high gas content is detected. Later, can choose</p>

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Operator Return to said site and complete drilling hole 616 at said site so that hydrocarbons in Formation 618 at said site can more efficiently be produced. Accordingly, the well completion design can be optimized in response to an output signal 646 and what is supplied via terminal means 648. Some well completion designs include, but are not limited to, change

<p>5 Alternatively, change the cement stabilization program, change the casing program or design, or improve the placement of downhole holes, slip sleeves, and slotted bushings. Improvements from these well completion alterations may include the inclusion of undesirable fluids down the well, such as unwanted water or gas, and may also include improving the isolation of areas from which production is undesirable. Moreover, adjacent wells can carry out 644a-c or output signals</p>

<p>10 646 Similar (interlinked) Similar improvements.</p>

In some embodiments, the resulting output signal 646 may also be configured to notify the operator via terminal devices 648 of the hazardous, corrosive, or otherwise toxic gases that may be trapped in the drilling fluid 622. The gases can form hazardous, corrosive, and/or Toxic, such as hydrogen sulfide (H2S) and the like, hazardous to drilling rig operators and the environment

<p>15th surrounding. In at least one embodiment, for example, the second output signal 644b of the second optical computer 640b can provide a real-time concentration of hydrogen sulfide (H₂S) retained in drilling fluid 622 when it returns to the surface. If it exceeds the recorded level of H₂S A predefined "safe" boundary, the signal handler 642 can be configured to trigger an alarm by sending the resulting output signal 646 to the terminal 648 that denotes it. In response to an alarm, it can</p>

<p>20 Operated by closing the well or adding H2S scavenging agents or other additives to the drilling fluid 622 via the 638 hopper to remedy the situation.</p>

In some embodiments, the dangerous, corrosive, or otherwise toxic gas can be methane trapped in drilling fluid 622. Since methane is considered highly explosive, excessive amounts of gas in return drilling fluid 622 can present a significant hazard to operators. device operation

<p>25 drilling and the surrounding environment. Accordingly, if an excessive amount of methane is detected by, for example</p>

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For example, the second optical computing device 640b, beyond a predetermined "safe" limit, the signal processor 642 can be configured to trigger an alarm via the output signal 646 and the peripheral means 648. In response to the alarm, the operator can handle the situation. For example, the operator may "shut down" the well using a surge arrester or the like and then

<p>5 Controlled extraction of methane using throttle and suppression lines connected to surge arresters.</p>

In some embodiments, the drilling fluid 622 returning to the surface can be monitored using the third optical computer 640G before depressurization is complete. As shown, the third optical computational device 640G can be placed in a connected position through the fluid with the associated flow line

<p>10 interstitial 630 after borehole 627 and otherwise placed before throttle valve 628.</p>

Similar to the second optical computer 640b, the third optical computer 640c can be configured to monitor the drilling fluid 622 after returning to the surface for gases (both hydrocarbon and non-hydrocarbon) that may have been trapped in it after circulating through the drilling hole 616. When it exits Drilling fluid 622 from throttle valve 628, any gases trapped in it will flow directly or

<p>15th Otherwise precipitation from drilling fluid 622. Accordingly, a third optical computational device 640C can be useful in providing a real-time or near-real-time concentration of one or more of the gases in the drilling fluid 622 as it rotates at or near Actual downhole environment conditions. The 644g output signal from the third optical computer 640g can, therefore, be useful in gas analysis by recording the mud performance of drilling fluid 622 at the conditions of</p>

<p>20 Operating down the well.</p>

Similarly to the second optical computer 640b, the third optical computer 640c can be configured to detect and record excess quantities of preferred gas in the drill hole 616. The resulting output signal 646 can then notify the operator that a specific type or quantity of preferred gas is present. In the 616 drilling hole and, as a result, one drilling variable can be set

<p>25 At least in response to it. For example, the operator can change the routing</p>

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Ground the drill bit 614 so that the drill hole 616 can be drilled or shaped to a large extent in the said layer or area. In ballistic drilling holes 616, the operator may be able to record an area of ​​the drilling hole 616 in which a high gas content is detected and, at a later time, return to said location and complete the drill hole 616 at said location so that

<p>5 more efficiently produce the hydrocarbons in Formation 618 at the said location.</p>

The third optical computer 640G can also be configured to detect hazardous, corrosive, or otherwise toxic gases (ie, H₂S, methane, etc.) that may be trapped in the drilling fluid 622. The resulting output signal 646 in these cases can notify the operator via terminal means 648 of the presence of said gases, and the operator can then handle the situation 10 In other embodiments, the 642 signal processor can self-process the mode,

Such as by closing the well or adding H2S scavenging agents or other additives to the drilling fluid 622 through the 638 hopper to remedy the situation. For example, as briefly mentioned above, the signal processor 642 could be in connection with an automated control system (not shown) which could be configured to take the required corrective action.

<p>15th It is recognized that the many embodiments herein destined for computer control networks and artificial neural networks, including many frameworks, modules, objects, components, methods and algorithms, can be implemented using computer components, programs, combinations thereof, and the like. To illustrate the interchangeability of computer components and programs, many frameworks, modules, components, components, methods and illustrative algorithms are generally described in terms of their function.</p>

<p>20 Whether the functionality is implemented as a computer component or software will depend on the specific application and any design limitations imposed. For this reason at least, it will be realized that people of ordinary skill in the field can perform the described function in a variety of ways for a specific application. Moreover, many components and frameworks can be arranged in a different order or divided differently, for example, without departing from the scope of publicly described embodiments.</p>

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Computer components used to implement the many frameworks, modules, items, components, methods, and demonstration algorithms described herein may include a processor configured to execute one or more sequences of instructions, programming states, or code stored on a non-computer-readable temporary medium. The processor could, for example, be a microprocessor used for purposes

<p>5 Generic, microcontroller, digital signal processor, application-specific embedded circuit, in-situ programmable gate array, programmable logic device, controller, state machine, gateway logic, distinct computer components, artificial neural network, or any other suitable entity that can To perform arithmetic or other data manipulations. In some embodiments, computer components may also include items such as, for example, memory (for example, random access memory).</p>

<p>10 access memory (RAM), flash memory, read only memory ROM, programmable read only memory PROM, erasable read only memory (EPROM registers, Hard disks, removable disks, DVDs, CD-ROMS, and any other suitable storage medium.</p>

<p>15th The executable sequences described here can be executed by one or more in-memory code sequences. In some embodiments, this code can be read into memory from another machine-readable medium. Executing sequences of instructions contained in memory can cause the processor to perform the process steps described here. One or more processors in a multiprocessing setup can also be used to execute instruction sequences in memory. In addition, a circle can be used</p>

<p>20 Fixed in place of or in combination with program instructions to implement many of the embodiments described here. Thus, current embodiments are not limited to any specific combination of computer hardware and/or software.</p>

As used herein, a machine-readable medium will refer to any medium that directly or indirectly provides instructions to a processor for the purpose of execution. Machine-readable media can take many forms, which include, for example, non-volatile media, volatile media, and transmission media.

<p>25 Non-volatile media can include, for example, optical and magnetic disks.</p>

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Volatile media can include, for example, dynamic memory. The transmission media can include, for example, coaxial cable, wire, optical fibers, and wires that form a bus. Generic images of machine-readable media can include, for example, floppy disks, soft disks, hard disks, magnetic tapes, other similar magnetic media, CD-ROMs,

<p>5 DVDs, other similar optical media, punch cards, paper tapes and similar physical media with modular holes, EPROM, PROM, ROM, RAM, and flash EPROM.</p>

It should also be realized that many drawings here must not be scaled, as they are optically correct as those skilled in the field of optics will perceive. Instead, the graphics are illustrative in nature only and are generally used here to complete an understanding of the systems and methods

<p>10 contained here. Indeed, while the drawings are not optically accurate, the conceptual interpretations depicted in them accurately reflect the illustrative nature of many of the embodiments that have been revealed.</p>

Embodiments disclosed herein include embodiment (A), embodiment (B), and embodiment (C).

Embodiment A: A system comprising: a flow path that circulates a drilling fluid in and out of a drilling hole penetrating a subsurface formation during a drilling operation, wherein the flow path includes a gas discharge device that includes a fluid inlet

<p>15th Drilling, drilling fluid outlet, and gas outlet, and where the gas outlet is coupled through the fluid to a configured gas analyzer to produce a first output signal, a second output signal, and a third output signal corresponding to a first gas concentration, second gas, and third gas, respectively; A first integrated computer element and a second integrated computer element are positioned along the flow path before the drilling fluid inlet of the gas discharge device and are configured to photoreact with the drilling fluid and produce a four output signal and a fifth output signal, respectively, corresponding to the gas concentration</p>

<p>20 the first in the drilling fluid and the second gas concentration in the drilling fluid, respectively; A signal processor that is intimately coupled to the first ICI, the second ICI, and the gas analyzer, whereby the signal processor is configured to do the following (1) receive the first output signal, the second output signal, the third output signal, the four output signal, and the output signal Fifth, (2) Calculation of a calibration factor based on the analysis of the first output signal in relation to the four output signal and the . signal</p>

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the second output relative to the fifth output signal, and (3) applying a calibration factor to the third output signal to produce a calibration output signal corresponding to the calibrated concentration of the third gas.

Embodiment A may include one or more of the following additional elements in any combination: Element (A1): The system also includes a third embedded computing element and four embedded computer elements.

<p>5 placed between the gas outlet of the gas degassing device and the gas analyzer device and configured to (1) photoreact with the gas composition extracted from the drilling fluid by the gas discharge device and (2) produce a sixth output signal and a seventh output signal, respectively, corresponding to the concentration of the first gas present in the gas composition and the concentration of the second gas present in the gas composition, respectively; and where the signal processor is configured to (1) receive the sixth output signal and the seventh output signal, and (2) also perform the calculation</p>

<p>10 Calibration factor based on the analysis of the first output signal for the four and sixth output signals and the second output signal for the fifth and seventh output signals; Element (A2): The system also includes one or more of the peripheral devices connected in connection with the signal processor and configured to receive the calibrated output signal from the signal processor and report the calibrated concentration of the third gas to the well operator; Element (A3): Element (A2) where One or more terminal devices are also configured</p>

<p>15th to adjust one or more drilling process variables in response to the titrated concentration of the third gas; Element (A4): where at least one of the first gas and the second gas is from the subterranean formation; Element (A5): where the first gas and the second gas are from the aquifer formation; Element (A6): where the first gas or the second gas is for methane; and element (A7): where the first gas or the second gas is carbon dioxide.</p>

<p>20 By way of non-exhaustive, illustrative combinations applicable to embodiment A include: A5 in combination with A6 and optionally A7 A5 in combination with A7 Element ) A4 in combination with A7, at least one of A1-(A3) in combination with any of the above, A1 in combination with A2 and optionally A3.</p>

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Embodiment B: A method comprising: circulation of a drilling fluid in a flow path extending in and out of a drilling hole penetrating a subsurface formation during drilling operations and including a gas discharge device having a drilling fluid inlet, drilling fluid outlet, and gas outlet; producing a first output signal, a second output signal, and a third output signal corresponding to a concentration of a first gas, a second gas, and a third gas using a gas analyzer device coupled through the fluid to the gas outlet

<p>5 gas degassing device; produce a four output signal using a first iC and a fifth output signal using a second iC positioned along the flow path before the drilling fluid inlet to the gas discharge device corresponding to the first gas concentration in the drilling fluid and the second gas concentration in the drilling fluid, respectively; Receiving the first output signal, the second output signal, the third output signal, the four output signal, and the fifth output signal using an asymmetrically coupled signal processor</p>

<p>10 connected to the gas analyzer, the first optical computer, and the second optical computer; Calculation of a calibration factor based on the analysis of the first output signal for the four output signal and the second output signal for the fifth output signal; The calibration factor is applied to the third output signal to produce a calibration output signal corresponding to the calibrated concentration of the third gas.</p>

embodiment (b) may include one or more of the following additional elements in any combination:

<p>15th Element (B1): The method also includes the production of a sixth output signal using a third computer element and a seventh output signal using a four computer integrated element placed between the gas outlet of the gas discharge device and the gas analysis device corresponding to the concentration of the first gas present in the composition of the gas extracted from the drilling fluid by means of a vacuum device gas and the concentration of the second gas present in the gas composition, respectively; receiving the sixth output signal and the seventh output signal using the signal processor coupled to the</p>

<p>20 Syntax related to the third optical computer and the fourth optical computer; The calibration factor is also calculated based on the analysis of the first output signal for the four and sixth output signals and the second output signal for the fifth and seventh output signals; Element (B2): The method includes element (B1) and also includes the transmission of the calibrated output signal to one or more terminal devices; setting one or more of the drilling or completion variables in response to the calibrated concentration of the third gas;</p>

<p>25 Element (B3): where there is at least one of the first gas and the second gas of formation </p>

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subterranean Element (B4): where the first gas and second gas are from the aquifers Element (B5): where the first gas or second gas is methane Element (B6): where the first gas or second gas is carbon dioxide; Element (B7): The method further includes the transmission of the calibrated output signal to one or more peripheral devices; and the tuning of one or more of the

<p>5 drilling or completion variables in response to the titrated concentration of the third gas; Element (B8): Element (B7)</p>

where adjusting one or more drilling or completion variables includes changing the ground orientation of the drill bit; and element (B9): element (B7) where adjusting one or more drilling or completion variables includes at least one change of cement stabilization program, change of casing programme, change of casing design, improvement of downhole bore placement, slip bushings, slotted bushings, and improve

<p>10 Isolate areas from which production is undesirable.</p>

By way of non-exhaustive, illustrative combinations applicable to embodiment B include: element (B4) in combination with element (B5) and optionally element (B6), element (B4) in combination with element (B6), element ( B3) in combination with at least one of the elements (B6), at least one of the elements (B3)- (B6) in combination with at least one of the elements (B7)-(B9), one on

<p>15th The least of the elements (B3)- (B6) in combination with at least one of the elements (B1)- (B2), element (B1) in combination with element (B2), and element (B1) in combination with element (B7) and on To optional at least one of the items (B8)-(B9).</p>

Embodiment (C): A method comprising: circulation of a drilling fluid in a flow path extending in and out of a drilling hole penetrating a subsurface formation during a drilling operation and including a gas discharge device having a drilling fluid inlet, drilling fluid outlet,

<p>20 gas outlet; production of a first output signal, a second output signal, and a third output signal corresponding to a concentration of a first gas, a second gas, and a third gas using a gas analyzer device coupled through the fluid to the gas outlet of the gas discharge device; Producing a four output signal using a first computed element and a fifth output signal using a second computed element placed along the flow path before the drilling fluid inlet to the gas discharge device corresponding to the first gas concentration present in the drilling fluid and the gas concentration four present in</p>

<p>25 drilling fluid, respectively; Receive the first output signal, the second output signal, the third output signal,</p>

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the four output signal, and the fifth output signal using a signal processor that is intimately coupled to the gas analyzer, the first optical computer, and the second optical computer; Calculation of a calibration factor based on the analysis of the first output signal for the four output signal and the second output signal for the fifth output signal; and applying the calibration factor to the third output signal to produce a signal

<p>5 A calibration output corresponding to the calibrated concentration of the third gas.</p>

Embodiment C may include one or more of the following additional elements in any combination: Element (C1): where at least one of the first gas and second gas is not from the subterranean formation; Element (C2): where the first gas and the gas The second result from the underground formation; Element (C3): where the first gas or the second gas is methane; Element (C4): where

<p>10 The first gas or the second gas is carbon dioxide; Element (C5): The method also includes the transmission of the calibrated output signal to one or more peripheral devices.</p>

As an unconstrained example, illustrative combinations applicable to embodiment C include: element (C2) in combination with element (C3) and optionally element (C4), element (C2) in combination with element (C4), element ( C2) in combination with element (C4), and at least one of

<p>15th Elements (C1)- (C4) in combination with element (C5).</p>

Thus, the current disclosure is well configured to achieve the stated purposes and advantages as well as those inherent in it. The specific embodiments disclosed above are illustrative only, as the present disclosure can be modified and implemented in different but equally clear ways for those skilled in the art immediately upon making use of the information herein. Moreover, there are no restrictions on creation details or

<p>20 design mentioned herein, other than as described in the safeguards below. Consequently, it will be evident that the specific illustrative embodiments disclosed above can be changed, combined, or modified, and all such variations fall within the scope and substance of the present disclosure. The disclosure illustratively described herein may be adequately implemented in the absence of any element not specifically disclosed herein and/or any optional element disclosed herein. While the compositions and methods of . are described</p>

<p>25 Where it "includes", "contains", or "includes" several components or steps, </p>

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That formulations and methods are 'mainly composed of' or 'consisting of' many components and steps. All numbers and ranges disclosed above can vary by some quantity. Wherever a minimum and maximum numeric range is disclosed, any number and any contained range that falls within the range shall be specifically disclosed. Specifically, it must be recognized that each range of values ​​(in the form of 'from about A to

<p>5 about b", or equivalently, "from about a to b", or equivalently, "from about a to b") disclosed herein showing any number and range included in the wider range of values. Likewise, the terms given have In the elements of protection their ordinary explicit meaning unless the contrary is publicly and clearly specified by the patentee.Moreover, the indefinite articles, as used in the claims, are defined here as meaning one or more of one of the elements to which they refer.</p>

<p>10 Graphics reference</p>

Figure 1:

A - physical thickness (nm)

b - air

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