Method for evaluating wellbore gas measurements

Abstract

A method for evaluating wellbore gas measurements includes determining drilling and environmental conditions corresponding to the measurements and calculating an interpretation confidence index for the measurements based on selected ones of the drilling and environmental conditions. The interpretation confidence index provides an assessment of the degree to which the measured composition reflects the actual reservoir gas composition.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims priority to and the benefit of European application number 23306630.7 filed on September 28, 2023, the entire contents of which are incorporated herein by reference. Background Art

[0003] When drilling a well for producing hydrocarbons, drilling fluids are usually circulated through the well for a variety of purposes. For example, drilling fluids are usually intended to provide pressure to underground formations, cool and lubricate the drill bit, flush drill cuttings from the drill bit and transport them to the surface, and provide hydraulic power to various downhole tools. Drilling fluids also usually carry formation fluids and dissolved formation gases to the surface. This gas can be released by the drill bit when the drill bit cuts the formation, and can include various alkane gases, such as methane (C1), ethane (C2), propane (C3), butane (C4), pentane (C5), etc., as well as artificially produced olefins, alcohols, and other polar pollutants derived from the degradation of drilling fluids driven by drilling operations.

[0004] The released gases are usually evaluated at the surface while drilling (e.g., by gas chromatography). Such measurements can provide valuable information to the mud logging tool and can provide information about the maturity and nature of the hydrocarbons in the reservoir, the demarcation of intervals and oil quality in the reservoir being drilled, as well as information about production zones, lithologic changes, reservoir accumulation history, seal effectiveness, and the environmental impact of the drilling operation.

[0005] While such gas measurements can provide valuable insights into the reservoir contents, the gas concentrations measured at the surface can sometimes differ (even significantly) from the actual reservoir gas composition. Industry needs to assess how well gas composition measurements made at the surface reflect the actual reservoir gas composition. BRIEF DESCRIPTION OF THE DRAWINGS

[0006] For a more complete understanding of the disclosed subject matter and advantages thereof, reference is now made to the following description taken in conjunction with the accompanying drawings, in which:

[0007] Figure 1 An exemplary drilling rig including the disclosed system for making and evaluating gas composition measurements is depicted.

[0008] Figure 2 Another embodiment of a surface system for making and evaluating gas composition measurements is depicted.

[0009] Figure 3A and 3B (collectively, FIG. 3 ) depicts a flow chart of an example method for making and evaluating gas composition measurements.

[0010] Figure 4A , Figure 4B , Figure 4C , Figure 4D and Figure 4E (collectively, FIG. 4 ) depict example lookup tables for assigning coefficients from which interpretation confidence indices may be determined.

[0011] Figure 5 A graphical representation of the coefficients for multiple environmental and measurement conditions is depicted. DETAILED DESCRIPTION

[0012] Embodiments of the present disclosure include methods and systems for making and evaluating drilling fluid gas composition measurements. In an exemplary embodiment, the disclosed method includes measuring the composition of a gas sample obtained during a mud logging operation. The gas sample includes at least a selected alkane gas. The method also includes determining an interpretation confidence index corresponding to the measured drilling and environmental conditions, and calculating an interpretation confidence index for the measured composition based on selected drilling and environmental conditions in the drilling and environmental conditions. The interpretation confidence index is intended to provide an assessment of the extent to which the measured composition reflects the actual reservoir gas composition.

[0013] Figure 1 An exemplary drilling rig 20 including a system 80 for making and evaluating drilling fluid gas composition measurements is depicted. The drilling rig 20 may be positioned above a subterranean formation (not shown). The drilling rig 20 may include, for example, a derrick and a hoisting apparatus (also not shown) for raising and lowering a drill string 30, which, as shown, extends into a wellbore 40 and includes, for example, a drill bit 32 and one or more downhole measurement tools 38 (e.g., logging while drilling tools or measurement while drilling tools) in a bottom hole assembly (BHA) above the drill bit 32. Suitable drilling systems, including, for example, drilling, steering, logging, and other downhole tools, are well known in the art.

[0014] The drilling rig 20 also includes a surface system 50 for controlling the flow of drilling fluid used on the drilling rig (e.g., for drilling out the wellbore 40). In the depicted exemplary drilling rig, the drilling fluid 35 can be pumped downhole (as depicted at 92), for example, via a conventional mud pump 57. The drilling fluid 35 can be pumped in route to the drill string 30, for example, through a riser 58 and a mud hose 59. The drilling fluid 35 is typically discharged from the drill string 30 at or near the drill bit 32 and creates an upward mud flow 94 through the wellbore annulus 42 (the annular space between the drill string and the wellbore wall). The drilling fluid 35 then flows through the return conduit 52 to the mud pit system 56, where it can be recirculated. It should be understood that the terms drilling fluid and mud are used synonymously herein.

[0015] The circulating drilling fluid 35 is intended to perform a number of functions during the drilling operation, one of which is to transport drill cuttings 45 to the surface (in an upward flow 94). The drill cuttings 45 are typically removed from the return mud via a shale shaker 55 (or other similar solids control device) in a return conduit (e.g., immediately upstream of a mud pit 56). Gases released or generated during drilling may also be transported to the surface in the circulating drilling fluid. These gases, which may be dissolved in the mud or dissolved in the form of bubbles, are typically removed from the drilling fluid, for example, via one or more degassers 54 located in or near a header tank 53, which is immediately upstream of the shale shaker 55 in the exemplary depiction. The drill cuttings 45 and the extracted gas are typically inspected at the surface to assist the drilling operation and to evaluate the formations and reservoirs through which the wellbore is drilled.

[0016] As is known to those of ordinary skill in the art, formation gas can be released into the wellbore 40 via the drilling process (e.g., by crushing the formation rock through the mechanical action of the drill bit), and can also migrate into the wellbore 40, for example, via fractures in the formation rock. The drilling process can also produce gas, for example, via drill bit metamorphism (DBM). Once in the wellbore, the gas can be transported to the surface via the drilling fluid (in the upward flowing fluid 94). The gas can be in solution in the drilling fluid (dissolved in the drilling fluid) and / or in the form of bubbles, and can be sampled in the surface system, for example, via one or more drilling fluid degassers 54 and / or headspace gas probes. The disclosed embodiments are not necessarily limited to how the gas is sampled.

[0017] Further references Figure 1, the drilling rig 20 may also include a testing facility 60 (e.g., a mud logging system or a laboratory trailer including one or more instruments suitable for making various measurements of sampled gases in the drilling fluid). In the depicted embodiment, the testing facility 60 has instruments (such as gas chromatography equipment) and is configured to measure the formation gas composition. Of course, the testing facility 60 may include many other testing instruments known to ordinary technicians. The facility may also include a system 80, which is configured to evaluate the gas composition measurement (e.g., to determine a confidence index of the proximity of the inferred gas measurement value to the reservoir composition). The system may include the instrument, or may be configured to receive the gas composition measurement from the instrument (e.g., gas chromatography equipment). Of course, the testing facility 60 may include many other testing instruments known to ordinary technicians and computer hardware and software configured to evaluate the gas composition measurement and various drilling and environmental conditions. The hardware may include one or more processors (e.g., microprocessors) that may be connected to one or more data storage devices (e.g., hard drives or solid-state memory) and a user interface. It will be further understood that the disclosed embodiments may include processor executable instructions stored in the data storage device. Of course, the disclosed embodiments are not limited to the use or configuration of any particular computer hardware and / or software.

[0018] Of course, it should be understood that although Figure 1 An onshore drilling rig 20 is depicted, but the disclosed embodiments are equally well suited for onshore or offshore drilling rigs. As known to those of ordinary skill in the art, an offshore drilling rig typically includes a platform deployed atop a riser extending from the seafloor to the surface. A drill string extends downward from the platform, through the riser, and into the wellbore through a blowout preventer (BOP) located on the seafloor. The disclosed embodiments are expressly not limited in these respects.

[0019] Figure 2 Another view of a portion of the surface system 50 is depicted. As described above, the return conduit 52 is configured to transport the drilling fluid 35 (sometimes including gas bubbles 37) from the wellbore 40 to the mud pit 56. The exemplary system 50 includes a degasser 54, which is deployed, for example, in or near a header tank 53, which is immediately upstream of the mud shaker 55 and the mud pit 56. In this exemplary configuration, the degasser 54 is configured to remove gas (referred to in the industry as gas-out) from the drilling fluid that is gushing from the wellbore 40. It should be understood that the disclosed embodiments are not limited in this regard. For example, the degasser 54 may include a first degasser and a second degasser, the first degasser being configured to perform a gas out measurement, and the second degasser being arranged downstream of the mud pump to perform a gas in measurement.

[0020] It should also be understood that the disclosed embodiments are not limited to use of the depicted degasser. Alternative embodiments may also (or additionally) utilize a gas probe located in the conduit 52 or at the surface of the well 40. In an exemplary embodiment, the degasser (or degasser) 54 may be piped directly to a mud logging unit or rig lab 60 (e.g., as shown at 65), for example, to automatically deliver sampled gas for composition testing.

[0021] It should be understood that the system 50 may include substantially any suitable degasser (or multiple degassers) 54, including, for example, vacuum degassers, centrifugal degassers, and impeller degassers. The degasser 54 may also be configured to heat the drilling fluid 35 to promote enhanced degassing of the fluid. The disclosed embodiments are not limited to the type of degasser employed. In addition, although not depicted, the system 50 may include one or more pumps (e.g., suction pumps or booster pumps) configured to pump sampled gas from the degasser 54 and / or the gas probe to the laboratory 60. Of course, the disclosed embodiments are not limited to any sampling, pumping, or gas delivery configuration.

[0022] Figure 3A and 3B (collectively, FIG. 3 ) depicts a flow chart of example methods 100 and 120 for making and evaluating gas composition measurements. Methods 100 and 120 may be performed, for example, while drilling a subterranean wellbore. Figure 3A In the method 100, the concentration of a selected alkane gas in a circulating drilling fluid may be measured at 102 while drilling a wellbore. Various drilling and environmental conditions, such as weight on bit (WOB), drill string rotation rate (RPM), penetration rate (ROP), atmospheric / weather conditions including temperature and atmospheric pressure, and drilling fluid temperature, may be measured / determined at 104 while drilling the wellbore. The determined conditions and a specified mud logging service configuration (e.g., including a drilling fluid degassing configuration and measurement equipment) may be evaluated at 106 to calculate a gas composition interpretation confidence index (ICI). The calculated ICI may provide an indication of how close the gas composition measurements made at 102 are to the actual reservoir fluid (gas) composition (or the confidence with which the measurements can be trusted to indicate the actual reservoir composition and properties). The method 100 may also optionally include evaluating the calculated ICI, the measured conditions, and the known configuration of the rig surface system and the drilling fluid degassing configuration at 108 to recommend changes to the mud logging operation (e.g., a new service configuration) to improve the ICI.

[0023] exist Figure 3B, method 120 may include obtaining a gas sample by degassing a drilling fluid used in drilling a wellbore at 122, measuring the concentration of selected alkane gases in the gas sample at 124, and monitoring / measuring the various drilling and environmental conditions described above at 126 while drilling. The degassing / measurement configuration (service configuration) may be defined (input), for example, by an operator at 128. For example, based on the defined gas extraction / measurement configuration at 128 and the measured values ​​of the drilling conditions at 126, coefficients may be assigned to each selected one of the drilling and environmental conditions at 130. At 132, a gas composition interpretation confidence index (ICI) may be calculated from the assigned coefficients (e.g., by calculating a sum or weighted sum of the assigned coefficients based on an applied criterion). As described above with respect to method 100, the calculated ICI may provide an indication of how close the gas composition measurements made at 122 are to the actual reservoir fluid (gas) composition (and how close the interpreted fluid type and properties are to the actual fluid type and properties). The method 120 may also optionally include evaluating the coefficients at 134 to recommend changes to drilling and mud logging operations to improve the ICI.

[0024] Continuing with reference to FIG. 3 , gas measurements can be made at 102 and 124 while drilling (e.g., at substantially any suitable time intervals while drilling), and the measured composition (e.g., molecular composition) can be matched to the depth of the hydrocarbon source during drilling using mud logging techniques known to those of ordinary skill. Furthermore, the measurements can be made using substantially any suitable service configuration, including substantially any gas measurement equipment and / or degasser. Furthermore, in certain embodiments, the drilling rig can include first and second mud logging systems, e.g., the first mud logging system is primarily used for safety of drilling operations and the second mud logging system is used to evaluate the reservoir. In such embodiments, the ICI can be calculated for measurements made by either or both of the systems.

[0025] Gas measurements can be performed, for example, using a gas chromatograph (GC) device and / or a mass spectrometer (MS) device, and can quantify the amount of light alkanes and optionally other gases (e.g., olefins and alcohols) in a gas sample. In a preferred embodiment, the gas measurement quantifies at least the following light alkane gases: methane (C1), ethane (C2), propane (C3), n-butane (nC4), isobutane (iC4), n-pentane (nC5), and isopentane (iC5), however, the disclosed embodiments are not limited in this regard. In other embodiments, the gas measurement device can quantify C1 to C8 as well as aromatic compounds (such as benzene and toluene), cyclic compounds (such as cyclopentane, methylcyclohexane), and inorganic substances (such as hydrogen, helium, carbon monoxide, and carbon dioxide).

[0026] The gas sample can be obtained using substantially any suitable degasser configuration, including, for example, vacuum degassers, centrifugal degassers, and impeller degassers. The degasser can also be configured to heat the drilling fluid to facilitate complete degassing of the fluid. In addition, the gas sample obtained by degassing the drilling fluid can be pumped (e.g., by a suction pump or a booster pump) to a measurement device in a laboratory (such as described above with respect to Figure 2 described above).

[0027] In certain embodiments, the service configuration may include, for example, Fluid Analysis in Real Time Logging ("FLAIR") and FlairFlex services provided by SLB. FLAIR FlairFlex is a quantitative mud logging service that provides laboratory quality gas composition measurements of reservoir fluids during drilling and utilizes GC-MS to measure C1 to C5. FLAIR and FlairFlex type data may be used for hydrocarbon and fluid contact identification and inter-well and intra-well fluid facies mapping, and are described herein as exemplary surface fluid logging services.

[0028] It should be understood that the disclosed embodiments are not limited to the use of FLAIR or FlairFlex, and other gas analyzers may be used to obtain gas composition measurements that can be evaluated using the disclosed embodiments. The service configuration may include substantially any other suitable gas measurement equipment and degasser (commercial or not yet commercially available). In other embodiments, the service configuration may alternatively include various configurations of the PureFlex mud logging service configuration (available from SLB) or other reservoir fluid analysis (service) configurations. The gas measurement equipment may include, for example, GC-FID, GC-TCD, GC-MS, MS, absorption spectroscopy (e.g., IR, MID), and / or Raman spectroscopy.

[0029] Continuing with reference to FIG. 3 , the drilling and environmental conditions measured at 104 and 126 may include substantially any suitable conditions. For example, the conditions may include the type of drilling fluid used in the well, such as oil-based mud (OBM) or water-based mud (WBM), the temperature of the drilling fluid, the drilling WOB and drilling RPM, the drilling rate of penetration (ROP), and various atmospheric / weather conditions, including temperature and atmospheric pressure and diurnal temperature variations. The measured conditions may also include an assessment of drilling fluid contamination and an assessment of biodegradation of the obtained gas samples. Drilling fluid contamination may be assessed, for example, by calculating the ratio of butane and / or pentane to propane in the gas composition measurement (e.g., C4 / C3, C5 / C3, or C4·C5 / C3). For example, biodegradation may be assessed by calculating the ratio of isobutane to normal butane (iC4 / nC4), the ratio of isopentane to normal pentane (iC5 / nC5), or the ratio of ethane to propane (C2 / C3) in the gas composition measurement. The type of extraction efficiency calibration can also be considered.

[0030] The service configuration can be defined according to any criteria. For example, the make and type of the degasser can be defined as, for example, a heated or non-heated degasser. In addition, the number of degassers used can be defined as, for example, including a single exhaust degasser or a first exhaust degasser and a second intake degasser. The length of the gas line between the degasser and the measuring device can also be defined. The type of gas measuring device can also be defined, for example, to limit the range of alkane gases measured (e.g., C1-C5 or C1-C8) and other gases that can be measured (e.g., olefins or alcohols). Additional services (such as isotope measurements) and features (such as mud contamination removal) can also be defined.

[0031] At 130, selected ones of the drilling and environmental conditions may be evaluated in view of the defined service configuration to assign the above coefficients. In an example embodiment, the coefficients may represent penalties such as negative penalties for non-optimal conditions. Less optimal (more non-optimal) conditions may result in larger penalties (higher negative coefficients). In addition, when the conditions are considered optimal or near optimal (such that no penalty is applied), the coefficients may be set to zero.

[0032] For example, the coefficient can be assigned based on the surface temperature of the drilling fluid or the temperature of the drilling fluid arriving at the degasser. In such an embodiment, the criterion can be based on the measured surface temperature. For a service configuration employing a non-heated degasser, the coefficient (penalty) may be highly negative when the measured temperature of the drilling fluid arriving at the degasser is low (e.g., the temperature is below a threshold). When the surface temperature of the drilling fluid is high (above a threshold), the coefficient may be less negative at intermediate temperatures and zero (best case). The improvement in gas extraction efficiency as the fluid temperature increases can provide a rationale for this particular coefficient. In other exemplary embodiments, when the service configuration employs a heated degasser, the coefficient may be independent of temperature and may be set to zero, indicating no penalty.

[0033] As the depth of drilling increases, the formations generally become hotter. Therefore, the deeper the well, the hotter the mud is expected to return to the surface (depending on other factors, such as geothermal gradients, mud flow rates, mud cooling at the surface, and mud heat dissipation into the rock of the borehole through which the mud travels via the annulus of the well). Therefore, the meters of the first drilling of a well or section can provide the first return of the mud to the surface and a reference temperature that can be recorded. As drilling proceeds, subsequent mud temperature readings can be compared to the reference. When an unheated degasser is used, an increased penalty can be applied for higher differences.

[0034] In other exemplary embodiments, a large penalty (highly negative coefficient) may be applied when the drilling fluid is oil-based mud (OBM), and a relatively small penalty (smaller negative coefficient) may be applied when the drilling fluid is water-based mud (WBM). Furthermore, the penalty may only be applied to certain service configurations. In other service configurations, the penalty may only be applied when OBM is used. And in other service configurations, no penalty is applied regardless of the type of drilling fluid used.

[0035] In an exemplary embodiment, the coefficient may indicate a condition where drill bit deterioration (DBM) is likely. In such an embodiment, the coefficient may depend on whether OBM or WBM is employed in the wellbore. For example, when OBM is employed, a larger penalty (a more negative coefficient) may be assigned. In addition, the coefficient may depend on the measured ROP and / or RPM. For example, a first DBM coefficient may be assigned based on ROP, and a second DBM coefficient may be assigned based on RPM. In such an embodiment, the coefficient may be more highly negative when ROP is low (below a threshold) and when RPM is high (above a threshold). When ROP is above a threshold and RPM is below a threshold, the coefficient may be set to zero. Intermediate coefficient values ​​may also be assigned.

[0036] In other exemplary embodiments, a condensation coefficient may be assigned. For example, the condensation coefficient may be related to the temperature to which the gas line is exposed, such as the difference between daytime and nighttime temperatures and the length of the gas line. In service configurations employing non-heated gas lines, low temperatures may result in condensation of C4, C5 and above, particularly in long gas lines (thus affecting the measured gas ratios and corresponding interpretations). A large penalty (highly negative coefficient) may be applied when the difference between daytime and nighttime temperatures exceeds a threshold or when both daytime and nighttime temperatures are below a threshold. A smaller penalty (or no penalty) may be applied when the difference between daytime and nighttime temperatures is small (less than a threshold) or when both daytime and nighttime temperatures are warm (above a threshold). An intermediate coefficient may also be applied. In addition, in exemplary embodiments, a condensation coefficient may be applied only when a non-heated gas line is used.

[0037] Biodegradation coefficients may also be assigned. For example, when the ratio between iC4 and nC4 or between iC5 and nC5 exceeds a threshold, a highly negative coefficient may be assigned. Smaller negative coefficients may be assigned at smaller intermediate ratios, and no penalty may be assigned when the ratio is less than a threshold.

[0038] A mud contamination coefficient may also be assigned, which is intended to identify that the drilling fluid is contaminated with polar components (e.g., alcohols, amines, and ammonia), particularly in WBM. For example, a high negative coefficient may be assigned when the ratio of C4C5 to C3 exceeds a threshold. Smaller negative coefficients may be assigned at smaller intermediate ratios, and no penalty may be assigned when the ratio is less than a threshold.

[0039] Extraction efficiency coefficients (EECs) may also be assigned based on pre-drilling experimental assignments of EECs to each measured alkane or by statistical assignments of arbitrary values. The former approach allows for quantitative real-time mud gas measurements and may not receive a penalty (e.g., as in the FlairFlex option with EEC calibration mud service), while the latter approach may receive a small penalty. The lack of any EEC (which is only possible with a heated degasser) may result in the greatest loss. Additionally, in some example embodiments, the extraction efficiency coefficient may be positive, indicating the benefit of employing such a technique. For example, the use of certain techniques may provide a small positive coefficient, while other techniques may provide a large positive coefficient. Still others may provide no benefit, such that the coefficient may be set to zero.

[0040] It should be understood that in certain example embodiments, coefficients may be automatically assigned using a lookup table. For example, a suitable lookup table may include a list of tabulated coefficients for each selected environmental and measurement condition at each potential service configuration. In such an embodiment, the service configuration may be pre-selected (e.g., manually) at the start of the logging operation (e.g., by selecting the type of degasser and measurement equipment used). The mud type, temperature sensor type, and extraction efficiency calibration may also be pre-selected.

[0041] Now go to Figure 4A , 4B , 4C, 4D and 4E (collectively referred to as FIG. 4 ), the disclosed embodiments are described in more detail with respect to the following non-limiting examples. In this example, coefficients are listed for different environmental and measurement conditions for three different example service configurations. It should be understood that the disclosed embodiments are in no way limited to the standards and coefficients described herein. The disclosed embodiments are also not limited to any particular environmental and measurement conditions or any number of different service configurations. It should be understood that in practice, a large number of potential service configurations may be available and additional environmental and measurement conditions may be employed. It should also be understood that the coefficient values ​​may also depend on the properties of the oil field in which the wellbore is located (e.g., the characteristics of the reservoir and its contents).

[0042] exist Figure 4A, exemplary mud types and mud temperature coefficients are listed for three exemplary service configurations. In this particular example, when using OBM and WBM with the first service configuration, mud type coefficients of -2 and -1 may be assigned. For the second service configuration, when using OBM, a mud type coefficient of -1 may be assigned, and when using WBM, a mud type coefficient of 0 may be assigned. For the third service configuration, a mud type coefficient of 0 may be assigned to either OBM or WBM. For each of the first service configuration and the second service configuration, when the mud temperature is less than 25°C and between 25°C and 40°C, a mud temperature coefficient of -2 and -1 may be assigned. When the temperature is greater than 40°C, the mud temperature coefficient may be set to zero. When using the third service configuration (which may include, for example, a heated degasser), the mud temperature coefficient may also be set to zero at all mud temperatures.

[0043] exist Figure 4B , example first DBM coefficients and second DBM coefficients are listed for three example service configurations when OBM is used. In this particular example, for each of the first and second service configurations, when the ROP is less than 5 m / h and between 5 and 10 m / h, first DBM coefficients of -2 and -1 may be assigned. When the ROP is greater than 10 m / h, the first DBM coefficient may be set to zero. For the third service configuration, the first DBM coefficient may be half of the coefficients of the first and second service configurations. In addition, for each of the first service configuration and the second service configuration, when the RPM is greater than 500 and between 200 and 500, second DBM coefficients of -2 and -1 may be assigned. When the RPM is less than 200, the second DBM coefficient may be set to zero. For the third service configuration, the second DBM coefficient may be half of the coefficients of the first and second service configurations.

[0044] exist Figure 4C , example first DBM coefficients and second DBM coefficients are listed for three example service configurations when using WBM. In this particular example, the first DBM coefficient and the second DBM coefficient may be when using OBM ( Figure 4B ). For the third service configuration, when ROP is less than 5 m / h, the first DBM coefficient may be set to 0.5, and when RPM is greater than 500, the second DBM coefficient may be set to 0.5. Otherwise, the first DBM coefficient and the second DBM coefficient may be set to zero.

[0045] exist Figure 4D, exemplary mud contamination and biodegradation factors are listed for three exemplary service configurations. In this particular example, for the first and second service configurations, the mud contamination factor may be assigned a value of -2 when the ratio of C4C5 to C3 exceeds 10, a value of -1 when the ratio is between 5 and 10, and a value of 0 when the ratio is less than 5. For the third service configuration, the mud contamination factor may be set to zero for all ratios. As also shown, for each service configuration, the biodegradation factor may be assigned a value of -2 when the ratio of iC4 / nC4 exceeds 5, a value of -1 when the ratio is between 2 and 5, and a value of 0 when the ratio is less than 5.

[0046] exist Figure 4E , exemplary mud temperature increments and condensation coefficients are listed for three exemplary service configurations. It should be understood that the mud temperature increment is a measure of the difference between the measured surface drilling fluid temperature and a reference temperature measurement of the surface drilling fluid temperature at the beginning of the well or well section. In this particular example, for the first service configuration, the mud temperature increment coefficient may be set to -2 when the temperature difference is greater than 20°C, to -1 when the temperature difference is between 10°C and 20°C, and to 0 when the temperature difference is less than 10°C. The mud temperature increment coefficient may be set to zero for all measured temperature differences in the second and third service configurations.

[0047] Furthermore, for the first two service configurations, when the day temperature and / or the night temperature is below 0° C., the condensation coefficient may be set to -2, when both the day temperature and the night temperature are above 0° C. and at least one of the day temperature and the night temperature is below 15° C., the condensation coefficient may be set to -1, and when both the day temperature and the night temperature are above 15° C., the condensation coefficient may be set to 0. For the third service configuration, the condensation coefficient may be set to zero for all day and night temperatures.

[0048] Continuing with reference to FIG. 3 , the confidence index may be calculated at substantially any suitable interval while drilling (e.g., whenever a gas measurement is taken). The calculated confidence index may also be displayed in a log, for example, by plotting the confidence index value as a function of the measured depth of the wellbore. The confidence index may be depicted in the log as a pseudo-color indicator or a line graph. The disclosed embodiments are not limited in this regard.

[0049] Confidence indices may be evaluated to provide recommendations as further described above with respect to Figure 3. For example, environmental and measurement conditions with large negative coefficients (penalties) may be identified, and recommendations may be made to reduce these coefficients and thus improve confidence indices.

[0050] Figure 5A graphical representation of coefficients for a number of example environments and measurement conditions for a given depth interval is depicted. In the depicted example, the coefficients assigned for each of the ten environments and measurement conditions are depicted along the corresponding axis. In this particular example, coefficients 2, 3, 4, and 5 can be easily identified as being highly negative (-2 in this particular example), while coefficients 1, 9, and 10 can be identified as being moderately negative (-1 in this particular example). In order to improve the confidence index (i.e., to achieve a confidence index closer to zero), a recommendation can be made, for example, to modify the service configuration so that coefficients 2, 3, 4, and 5 are less negative (e.g., have values ​​of 0 or -1 in this particular example).

[0051] It should be understood that the present disclosure includes many embodiments. These embodiments include but are not limited to the following embodiments.

[0052] In a first embodiment, a method for evaluating downhole gas composition measurements is disclosed. The method includes measuring a composition of a gas sample obtained during a mud logging operation, the composition including at least a selected alkane gas; determining drilling and environmental conditions corresponding to the measured composition; and calculating an interpretation confidence index for the measured composition based on selected ones of the drilling and environmental conditions, wherein the interpretation confidence index provides an assessment of the extent to which the measured composition reflects the actual reservoir gas composition.

[0053] A second embodiment may include the first embodiment, further comprising recommending a change to the mud logging operation based on the calculated interpretation confidence index.

[0054] A third embodiment may include any one of the first to second embodiments, wherein measuring the components includes measuring the components using a gas chromatography device or a mass spectrometer.

[0055] A fourth embodiment may include any one of the first to third embodiments, and further include specifying a mud logging service configuration, wherein the mud logging service configuration includes a type of degasser for obtaining the gas sample and a type of gas measurement equipment for performing the gas composition measurement, wherein the evaluation further includes evaluating the drilling and environmental conditions and the specified mud logging service configuration to estimate the interpretation confidence index.

[0056] A fifth embodiment may include any one of the first to fourth embodiments, wherein measuring the composition further comprises degassing a portion of the circulating drilling fluid to obtain the gas sample; and measuring the composition of the obtained gas sample.

[0057] A sixth embodiment may include any one of the first to fifth embodiments, wherein evaluating the drilling and environmental conditions further comprises assigning a coefficient to each selected one of the determined drilling and environmental conditions; and summing the assigned coefficients to calculate an interpretation confidence index.

[0058] A seventh embodiment may include the sixth embodiment, wherein the coefficients include a first drill bit metamorphism (DBM) coefficient and a second drill bit metamorphism (DBM) coefficient; the first DBM coefficient is assigned based on a measured drilling penetration rate and a type of drilling fluid from which the gas sample is obtained; and the second DBM coefficient is assigned based on a measured drill bit rotation rate while drilling and a type of drilling fluid from which the gas sample is obtained.

[0059] An eighth embodiment may include any one of the sixth to seventh embodiments, wherein the coefficients include a drilling fluid contamination coefficient and a biodegradation coefficient; the drilling fluid contamination coefficient is assigned based on the ratio of butane and / or pentane to propane in the measured components; and the biodegradation coefficient is assigned based on the ratio of isobutane to normal butane or isopentane to normal pentane in the measured components.

[0060] A ninth embodiment may include any one of the sixth to eighth embodiments, wherein the coefficients include a mud temperature coefficient and a condensation coefficient; the mud temperature coefficient is assigned based on the measured surface temperature of the drilling fluid; and the condensation coefficient is assigned based on daytime and nighttime temperature measurements taken at a drilling rig site where logging operations are performed.

[0061] A tenth embodiment may include any one of the sixth to ninth embodiments, wherein the assigning the coefficients and summing the assigned coefficients are performed automatically for each gas composition measurement.

[0062] In an eleventh embodiment, a system for evaluating downhole gas composition measurements is disclosed. The system includes a measurement device configured to measure a composition of a gas sample obtained during a mud logging operation, the composition including at least a selected alkane gas; and a processor configured to receive the measured gas composition from the measurement device; receive drilling and environmental conditions corresponding to the measured composition; and evaluate the drilling and environmental conditions to estimate an interpretation confidence index for the measured composition, wherein the interpretation confidence index provides an assessment of the extent to which the measured composition reflects the actual reservoir gas composition.

[0063] A twelfth embodiment may include the eleventh embodiment, wherein the processor is further configured to receive a specified mud logging service configuration, the specified mud logging service configuration including the type of degasser used to obtain the gas sample and the type of gas measurement equipment used to make the gas composition measurement and evaluate the drilling and environmental conditions and the specified mud logging service configuration to estimate the interpretation confidence index.

[0064] A thirteenth embodiment may include the twelfth embodiment, wherein the processor is further configured to assign a coefficient to each of selected ones of the received drilling and environmental conditions; and sum the assigned coefficients to calculate the interpretation confidence index.

[0065] A fourteenth embodiment may include the thirteenth embodiment, further comprising a lookup table stored in an electronic memory, the lookup table comprising a list of coefficients for each of selected environmental and drilling conditions for a plurality of different mud logging service configurations, wherein the processor is configured to retrieve the assigned coefficients from the lookup table based on the selected environmental and drilling conditions and the specified mud logging service configuration.

[0066] The fifteenth embodiment may include the fourteenth embodiment, wherein the lookup table includes at least the following coefficients: a first drill bit metamorphism (DBM) coefficient, which is assigned based on the measured drilling penetration rate and the type of drilling fluid from which the gas sample is obtained; a second DBM coefficient, which is assigned based on the measured rotation rate of the drill bit while drilling and the type of drilling fluid from which the gas sample is obtained; a drilling fluid contamination coefficient, which is assigned based on the measured ratio of butane and / or pentane to propane in the composition; a biodegradation coefficient, which is assigned based on the measured ratio of isobutane to normal butane or isopentane to normal pentane in the composition; a mud temperature coefficient, which is assigned based on the measured surface temperature of the drilling fluid; and a condensation coefficient, which is assigned based on daytime and nighttime temperature measurements taken at the drilling rig site where the logging operation is performed.

[0067] In a sixteenth embodiment, a method for evaluating downhole gas composition measurements is disclosed. The method includes obtaining a gas sample from a circulating drilling fluid during a mud logging operation; measuring the composition of the gas sample, the composition including at least a selected alkane gas; determining drilling and environmental conditions corresponding to the measured composition; specifying a mud logging service configuration, the mud logging service configuration including a type of degasser used to obtain the gas sample and a type of gas measurement equipment used to perform the gas composition measurement; assigning coefficients to selected ones of the determined drilling and environmental conditions based on the specified mud logging service configuration; calculating an interpretation confidence index based on the assigned coefficients, wherein the interpretation confidence index provides an assessment of the extent to which the measured composition reflects the actual reservoir gas composition.

[0068] A seventeenth embodiment may include the sixteenth embodiment, further comprising recommending a change to the mud logging operation based on the assigned coefficients and the calculated interpretation confidence index.

[0069] The eighteenth embodiment may include any one of the sixteenth to seventeenth embodiments, wherein the assigned coefficients include at least the following coefficients: a first drill bit metamorphism (DBM) coefficient, which is assigned based on the measured drilling penetration rate and the type of drilling fluid from which the gas sample is obtained; a second DBM coefficient, which is assigned based on the measured rotation rate of the drill bit during drilling and the type of drilling fluid from which the gas sample is obtained; a drilling fluid contamination coefficient, which is assigned based on the measured ratio of butane and / or pentane to propane in the composition; a biodegradation coefficient, which is assigned based on the measured ratio of isobutane to normal butane or isopentane to normal pentane in the composition; a mud temperature coefficient, which is assigned based on the measured surface temperature of the drilling fluid; and a condensation coefficient, which is assigned based on daytime and nighttime temperature measurements taken at the drilling rig site where mud logging operations are performed.

[0070] A nineteenth embodiment may include any one of the sixteenth to eighteenth embodiments, wherein the calculating includes summing the assigned coefficients to calculate the interpretation confidence index.

[0071] The twentieth embodiment may include any one of the sixteenth to nineteenth embodiments, wherein the assigning coefficients further comprises retrieving the assigned coefficients from a lookup table based on the selected environmental and drilling conditions and the specified mud logging service configuration, wherein the lookup table comprises a list of coefficients for each of the selected environmental and drilling conditions for a plurality of different mud logging service configurations.

[0072] Although the method for evaluating wellbore gas measurements has been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims.

Claims

1. A method for evaluating downhole gas composition measurements, the method comprising: measuring a composition of a gas sample obtained during a mud logging operation, the composition including at least a selected alkane gas; determining drilling and environmental conditions corresponding to the measured components; as well as An interpretation confidence index for the measured composition is calculated based on selected ones of the drilling and environmental conditions, wherein the interpretation confidence index provides an assessment of the extent to which the measured composition reflects actual reservoir gas composition. 2 . The method of claim 1 , wherein measuring the composition comprises measuring the composition using a gas chromatography device or a mass spectrometer.

3. The method of claim 1 further comprising specifying a mud logging service configuration including a type of degasser for obtaining the gas sample and a type of gas measurement equipment for making gas composition measurements, wherein the evaluation further comprises evaluating the drilling and environmental conditions and the specified mud logging service configuration to estimate the interpretation confidence index.

4. The method of claim 1 , wherein evaluating the wellbore and environmental conditions further comprises: for each partition coefficient for a selected one of the determined drilling and environmental conditions; as well as The assigned coefficients are summed to calculate the interpretation confidence index.

5. The method according to claim 4, wherein: The coefficients include mud temperature coefficient and condensation coefficient; The mud temperature coefficient is assigned based on a measured surface temperature of the drilling fluid; as well as Condensation coefficients are assigned based on daytime and nighttime temperature measurements taken at the rig site where mud logging operations are performed. The method of claim 4 , wherein assigning the coefficients and summing the assigned coefficients are performed automatically for each gas composition measurement.

7. A system for evaluating downhole gas composition measurements, the system comprising: a measurement device configured to measure a composition of a gas sample obtained during a mud logging operation, the composition including at least a selected alkane gas; as well as A processor configured to: receiving a measured gas composition from the measuring device; receiving drilling and environmental conditions corresponding to the measured components; as well as The drilling and environmental conditions are evaluated to estimate an interpretation confidence index for the measured composition, wherein the interpretation confidence index provides an assessment of how well the measured composition reflects the actual reservoir gas composition.

8. The system of claim 7 further comprising a lookup table stored in the electronic memory, the lookup table comprising a list of coefficients for each of selected environmental and drilling conditions for a plurality of different mud logging service configurations, wherein the processor is configured to retrieve the assigned coefficients from the lookup table based on the selected environmental and drilling conditions and the specified mud logging service configuration.

9. The system of claim 8, wherein the lookup table comprises at least the following coefficients: a first drill bit metamorphism (DBM) factor assigned based on a measured wellbore penetration rate and a type of drilling fluid from which the gas sample was obtained; a second DBM factor assigned based on a measured rotation rate of the drill bit while drilling and a type of drilling fluid from which the gas sample was obtained; a drilling fluid contamination factor assigned based on the ratio of butane and / or pentane to propane in the measured composition; a biodegradation factor assigned based on the ratio of isobutane to normal butane or isopentane to normal pentane in the measured components; a mud temperature coefficient assigned based on a measured surface temperature of the drilling fluid; and A condensation factor is assigned based on daytime and nighttime temperature measurements taken at the rig site where the mud logging operation is performed.

10. A method for evaluating downhole gas composition measurements, the method comprising: Obtaining gas samples from circulating drilling fluid during mud logging operations; measuring a composition of the gas sample, the composition comprising at least the selected alkane gas; determining drilling and environmental conditions corresponding to the measured components; specifying a mud logging service configuration including a type of degasser for obtaining said gas sample and a type of gas measurement equipment for making said gas composition measurements; assigning coefficients to selected ones of the determined drilling and environmental conditions based on the specified mud logging service configuration; An interpretation confidence index is calculated based on the assigned coefficients, wherein the interpretation confidence index provides an assessment of how well the measured composition reflects the actual reservoir gas composition.

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