Surface logging using detritus-based petrophysical analysis

Abstract

A drilling process method and system for drilling a well are described. The method includes performing a drilling operation through a downhole formation, the drilling operation generating drilling cuttings. A single drilling cutting sample is obtained at a location on the surface. An x-ray diffraction (XRD) and / or x-ray fluorescence (XRF) analysis is performed on the single drilling cutting sample. Elemental information and mineral information of the single drilling cutting sample is obtained from the XRF analysis about the downhole formation. At least one petrophysical property of the downhole formation is determined from the obtained information.

Description

Background Technology 1. Technical Field

[0002] This invention relates in general to downhole operations and systems for surface logging using rock cuttings-based rock physical analysis.

[0003] 2. Description of related technologies

[0004] Drilling boreholes deep underground is used for many applications, such as carbon dioxide sequestration, hydrogen storage, geothermal production, and oil and gas exploration and production. In all these applications, boreholes are drilled so that they penetrate or allow access to materials (e.g., gases or fluids) contained in strata located below the surface (e.g., sequestration chambers). Different types of tools and instruments can be set in the boreholes to perform a variety of tasks and measurements.

[0005] Various sensors can be used for logging and measurement during drilling operations (e.g., measurement-while-drilling and logging-while-drilling). Typically, such measurements are performed downhole using wirelines or a logging-while-drilling system. Surface-based data is usually wired and may include surface-based X-ray diffraction (XRD) and X-ray fluorescence (XRF) analyses performed on cuttings to determine elemental and / or mineral data. Improved data collection and analysis-while-drilling can be beneficial to the industry. Summary of the Invention

[0006] This paper discloses a system and method for surface-based rock physical analysis during drilling operations. The drilling process method includes: performing a drilling operation through the downhole formation, which generates drill cuttings; obtaining individual drill cuttings samples at a surface-based location; performing X-ray diffraction (XRD) and X-ray fluorescence (XRF) analysis on the individual drill cuttings samples; obtaining elemental information of the individual drill cuttings samples from the XRF analysis of the downhole formation; obtaining mineral information of the individual drill cuttings samples from at least one of the XRD and XRF analyses of the downhole formation; and determining at least one rock physical property of the downhole formation from the elemental and mineral information.

[0007] A drilling system according to some embodiments includes: a drilling rig including a drill string having a drill bit at its end for drilling a borehole through the formation; a surface-based cuttings collection device configured to obtain individual drilling cuttings samples; a cuttings analysis unit for performing at least one of X-ray diffraction (XRD) and X-ray fluorescence (XRF) analysis on the individual drilling cuttings samples; and a processing system. The processing system is configured to: obtain elemental information of the individual drilling cuttings sample from XRF analysis of the downhole formation; obtain mineral information of the individual drilling cuttings sample from at least one of XRD and XRF analysis of the downhole formation; and determine at least one petrophysical property of the downhole formation from the elemental and mineral information. Attached Figure Description

[0008] The subject matter considered to be in this invention is specifically pointed out and explicitly claimed in the claims at the end of this specification. The foregoing and other features and advantages of the invention will become apparent from the following detailed description taken in conjunction with the accompanying drawings, wherein similar elements have similar reference numerals, in which:

[0009] Figure 1 Examples of systems for performing downhole operations that can adopt embodiments of this disclosure;

[0010] Figure 2 This is the process according to the implementation scheme of this disclosure;

[0011] Figure 3 This is the process according to the implementation scheme of this disclosure;

[0012] Figure 4 This is a schematic diagram of a drilling system configured to perform an embodiment of this disclosure;

[0013] Figure 5A It is a schematic graph of the displayed data obtained according to the embodiments of this disclosure;

[0014] Figure 5B It shows Figure 5A A magnified portion of the schematic graph;

[0015] Figure 5C It shows Figure 5A A magnified portion of the schematic graph;

[0016] Figure 5D It shows Figure 5A A magnified portion of the schematic graph;

[0017] Figure 6A It is a schematic graph of the displayed data obtained according to the embodiments of this disclosure;

[0018] Figure 6B It shows Figure 6A A magnified portion of the schematic graph;

[0019] Figure 6C It shows Figure 6A A magnified portion of the schematic graph; and

[0020] Figure 6D It shows Figure 6A A magnified portion of the schematic graph. Detailed Implementation

[0021] Figure 1 A schematic diagram of a system for performing downhole operations is shown. As shown, the system is a drilling system 10, which includes a drill string 20 having a drilling assembly 90 (also referred to as a bottom hole assembly (BHA)) delivered in a borehole 26 penetrating the formation 60. The drilling system 10 includes a conventional derrick 11 erected on a base plate 12 supporting a rotary table 14 rotated at a desired speed by a prime mover (such as an electric motor (not shown)). The drill string 20 includes a drill pipe 22, such as a drill string, extending downwards from the rotary table 14 into the borehole 26. A fracturing device 50 (such as a drill bit attached to the end of the BHA 90) fractures the geological formation as it rotates to drill the borehole 26. The drill string 20 is connected to surface equipment, such as a system for lifting, rotating, and / or pushing (including but not limited to) the winch 30 via pulley 23 through the square drill pipe joint 21, swivel 28, and line 29. In some embodiments, the surface equipment may include a top drive (not shown). During drilling operations, the winch 30 is operated to control the pressure on the drill bit, which affects the drilling rate. The operation of the winch 30 is well known in the art and will not be described in detail herein.

[0022] During drilling operations, suitable drilling fluid 32 (also referred to as "mud") from the source or mud pit 31 is circulated under pressure through the drill string 20 by a mud pump 34. The drilling fluid 31 enters the drill string 20 via a wave eliminator 36, a fluid line 38, and a kerb joint 21. The drilling fluid 31 is discharged at the bottom of the borehole 51 through an opening in the fracturing device 50. The drilling fluid 31 circulates upwards along the wellbore through the annular gap 27 between the drill string 20 and the borehole 26, and returns to the mud pit 32 via a return line 35. A sensor S1 in the fluid line 38 provides information about the fluid flow rate. Surface torque sensors S2 and S3, associated with the drill string 20, provide information about the torque and rotational speed of the drill string, respectively. Additional sensors may be configured at the surface (e.g., as part of drilling system 10 and / or located downhole) and may include, but are not limited to, gas tomography sensors configured to monitor the gas content and composition of drilling fluid 31 while the drilling fluid is circulated. Some of these sensors may be configured with a response time (in minutes) longer than the transmission (in seconds) via electromagnetic telemetry using BHA embedded sensors. Additionally, one or more sensors associated with line 29 are used to provide hook load on drill string 20 and other desired parameters related to drilling of borehole 26. The system may also include one or more downhole sensors 70 positioned on drill string 20 and / or BHA 90.

[0023] In some applications, the fracturing device 50 is rotated solely by rotating the drill string 22. However, in other applications, a drill motor 55 (e.g., a mud motor) housed within the drilling assembly 90 is used to rotate the fracturing device 50 and / or to superimpose or supplement the rotation of the drill string 20. In either case, for a given formation and a given drilling assembly, the rate of penetration (ROP) of the fracturing device 50 into the formation 60 depends largely on the pressure on the drill bit and the drill bit rotation speed. Figure 1 In one aspect of the implementation, a drilling motor 55 is coupled to a fracturing device 50 via a drive shaft (not shown) disposed in a bearing assembly 57. The drilling motor 55 rotates the fracturing device 50 as drilling fluid 31 passes under pressure through it. The bearing assembly 57 supports the radial and axial forces on the fracturing device 50, the downward thrust of the drilling motor, and the reactive upward load from the applied drilling pressure. A stabilizer 58, coupled to the bearing assembly 57 and / or other suitable locations, acts as a centralizer for the drilling assembly 90 or a portion thereof.

[0024] One or more surface control units 40 may be configured to receive signals from downhole sensors 70 and equipment via transducers 43, such as pressure transducers, placed in fluid lines 38, as well as from sensors S1, S2, S3 (and other surface sensors), hook load sensors, RPM sensors, torque sensors, downhole sensors, and any other sensors used in the system, and process such signals according to programmed instructions provided to the surface control unit 40. The surface control unit 40 may be configured to display desired drilling parameters and other information used by operators at the drilling rig site to control drilling operations on one or more associated displays / monitors 42. The surface control unit 40 may include a computer; memory for storing processor-accessible data, computer programs, models, and algorithms; a recorder, such as a magnetic tape unit, memory unit, etc., for recording data; and other peripheral devices. The surface control unit 40 may also include a simulation model used by the computer to process data according to programmed instructions. The surface control unit is configured to respond to user commands entered via a suitable device, such as a keyboard. The surface control unit 40 may be configured to activate an alarm 44 in the event of certain unsafe or undesirable operating conditions.

[0025] Drilling assembly 90 also includes other sensors and devices or tools for providing various measurements related to the formation surrounding the borehole and for drilling the borehole 26 along a desired path. Such devices may include equipment for measuring formation resistivity near and / or in front of the drill bit, gamma-ray equipment for measuring formation gamma-ray intensity, and equipment for determining the drill string inclination, azimuth, and position. A formation resistivity tool 64, fabricated according to the embodiments described herein, can be coupled at any suitable location (including above the lower initiator assembly or steering unit 62) to estimate or determine the formation resistivity near or in front of the fracturing device 50 or at other suitable locations. Inclinometer 74 and gamma-ray equipment 76 may be suitably positioned to determine the inclination and formation gamma-ray intensity of the BHA, respectively. Any suitable inclinometer and gamma-ray equipment may be used. Additionally, an azimuth device (not shown) such as a magnetometer or gyroscope may be used to determine the drill string azimuth. Such devices are known in the art and therefore will not be described in detail herein. In the exemplary configuration described above, the drilling motor 55 transmits power to the fracturing device 50 via a shaft that also allows drilling fluid to be transferred from the drilling motor 55 to the fracturing device 50. In an alternative embodiment of the drill string 20, the drilling motor 55 may be coupled below the resistivity measuring device 64 or at any other suitable location.

[0026] Still referencing Figure 1Other logging-while-drilling (LWD) equipment (generally designated as 77 here), such as equipment for measuring formation porosity, permeability, density, rock properties, fluid properties, etc., may be placed in appropriate locations within the drilling assembly 90 to provide information for assessing the subsurface formation along the borehole 26. Such equipment may include, but is not limited to, temperature measuring tools, pressure measuring tools, borehole diameter measuring tools (e.g., calipers), acoustic tools, nuclear tools, nuclear magnetic resonance tools, and formation testing and sampling tools.

[0027] The aforementioned equipment transmits data to a downhole telemetry system 72, which in turn transmits the received data upwards along the wellbore to a surface control unit 40. The downhole telemetry system 72 also receives signals and data from the surface control unit 40 and transmits such received signals and data to appropriate downhole equipment. In one aspect, a mud pulse telemetry system can be used to transmit data between the downhole sensor 70 and equipment and surface equipment during drilling operations. A transducer 43, placed in a fluid line 38 (e.g., a mud supply line), detects mud pulses in response to data transmitted by the downhole telemetry system 72. The transducer 43 generates an electrical signal in response to changes in mud pressure and transmits such a signal via a conductor 45 to the surface control unit 40. In other respects, any other suitable telemetry system can be used for two-way data communication (e.g., downlink and uplink) between the ground and BHA 90. These telemetry systems include, but are not limited to, acoustic telemetry systems, electromagnetic telemetry systems, optical telemetry systems, and wired telemetry systems that can utilize wireless connectors or repeaters within the drill string or borehole. A wired telemetry system can be constructed by connecting drill pipe segments, each segment including a data communication link (such as an electrical wire) extending along the pipe. Data connections between segments can be made by any suitable method, including but not limited to hard electrical or optical connections, inductive, capacitive, resonant coupling (such as electromagnetic resonant coupling), or directional coupling methods. When coiled tubing is used as drill pipe 22, the data communication link can extend along the side of the coiled tubing.

[0028] The drilling systems described so far relate to those that utilize drill tubing to deliver drilling assemblies 90 into the borehole 26, where pressure on the drill bit is typically controlled from the surface by controlling the operation of a winch. However, a large number of current drilling systems, particularly those used for drilling highly skewed and horizontal boreholes, utilize coiled tubing to deliver drilling assemblies downhole. In such applications, thrusters are sometimes deployed in the drill string to provide the desired force at the drill bit. Additionally, when coiled tubing is used, the tubing is not rotated via a rotary table, but rather injected into the borehole via a suitable injector, while a downhole motor (such as drilling motor 55) rotates the fracturing equipment 50. For offshore drilling, offshore drilling rigs or vessels are used to support the drilling equipment, including the drill string.

[0029] Still referencing Figure 1 A resistivity tool 64 may be provided, which includes, for example, multiple antennas, including, for example, transmitters 66a or 66b and / or receivers 68a or 68b. Resistivity may be a formation property of interest when making drilling decisions. Those skilled in the art will understand that other formation property tools may be used in conjunction with or in place of the resistivity tool 64.

[0030] although Figure 1 This disclosure pertains to drilling operations, but those skilled in the art will understand that, despite the different components, similar configurations can be used to perform various downhole operations. For example, as known in the art, cabled, wireline, tailpipe drilling, reaming, coiled tubing, and / or other configurations can be used. Furthermore, production configurations can be employed for extracting materials from and / or injecting materials into the formation. Therefore, this disclosure is not limited to drilling operations but can be applied to any suitable or desired one or more downhole operations.

[0031] During drilling operations, difficulties can arise in collecting and processing data related to the downhole formation and its properties (e.g., rock properties). Typically, through-hole cable tools are used for formation analysis, such as rock properties and rock properties. However, data collection can be challenging in soft and thin unconventional shale and high-pressure, high-temperature formations. In such formations, it can be difficult to drive cable tools into the resulting borehole due to the relatively thin formation, and the risk of borehole damage or collapse is high when such cable tools are operated. Furthermore, soft / hazardous unconventional formations can complicate drilling because active data collection and analysis may be insufficient for real-time, field decision-making during drilling operations. Unconventional formation wells include, for example, shale wells, tight sandstone wells, high-pressure / high-temperature wells, carbonate wells, acidized wells, horizontal branch wells, and other types of wells. Moreover, the implementation schemes described herein can be applied to wells and drilling operations where it is impossible to operate cable tools and / or operating such cable tools may be difficult or expensive (e.g., wells with weak zones).

[0032] Various cable-based tools may be insufficient for formation analysis and / or have limitations. For example, total gamma-ray based tools may generate multiple results for a single formation, and therefore predictive modeling based on them may be uncertain and / or incomplete. In such data collection, high gamma-ray readings may indicate high potassium and / or uranium content in the formation or rock, but such information does not indicate rock strength and / or fracturing susceptibility, and may therefore lead to uncertainty during drilling and / or fracturing operations. Furthermore, the use of spectroscopic gamma-ray tools may be infeasible due to cost burdens and the risks associated with deploying such tools in unconventional formations. Similarly, resistivity data may be impractical in tight and / or unconventional formations.

[0033] Therefore, embodiments of this disclosure relate to cuttings-based methods for formation analysis (i.e., surface-based analysis). According to some embodiments, cuttings analysis can be performed using a single surface-based XRF tool (X-ray fluorescence), a single surface-based XRD tool (X-ray diffraction), or a combination of surface-based XRF and surface-based XRD tools to determine downhole formations. A single surface-based XRF tool can rapidly acquire elemental information from cuttings, and this elemental information can be used to calculate mineral and petrophysical data. This process can take approximately a few minutes in total. Data acquisition and analysis in the field (e.g., in-situ, at the well) takes significantly less time than a single XRD method. For example, an XRF process can take approximately 3 to 7 minutes, while an XRD process can take approximately 27 to 30 minutes. Typically, XRD is only used to verify or confirm mineral outputs and analyses from XRF processes. Therefore, XRF processing and analysis are considered faster and more efficient than XRD processing.

[0034] The surface-based cuttings analysis disclosed herein can be used for rock physical analysis in both unconventional and conventional formations. Furthermore, in some example configurations, such surface-based cuttings analysis, as disclosed herein, can be used in deep wells with a total vertical depth (TVD) of 6,000 meters or greater. In such deep wells, logging-while-drilling (LWD) acquisition may be difficult or impossible due to the downhole / formation temperatures being too high for this type of LWD data acquisition.

[0035] The output from such surface-based cuttings analysis is comparable to that of downhole tools, but offers lower deployment costs, safer operation, and less wellbore risk, particularly in unconventional formations. Furthermore, in addition to generating data similar to that of downhole wireline tools, embodiments of this disclosure can also provide petrophysical parameters and formation-related data. For example, wireline elemental logging can be used to acquire elemental data and calculate minerals, but is typically limited to about twenty elements and a few minerals. In contrast, according to some embodiments of this disclosure, for example, thirty-six (or more) elements and six to nine minerals can be identified, and additional petrophysical data can be obtained. It should be understood that embodiments of this disclosure are not limited to thirty-six elements and six to nine minerals, but this example is only used to illustrate the improved quality and data output of embodiments of this disclosure compared to wireline data acquisition. Moreover, because embodiments of this disclosure are not equipment-dependent, various different standard or specific XRF data systems and equipment can be employed, unlike downhole wireline tools which are specifically configured for downhole environments.

[0036] According to embodiments of this disclosure, surface-based cuttings analysis output can be used to optimize drilling procedures and operations, analyze wellbore risks during drilling, assess downhole bit performance, and provide data for post-drilling operations such as fracturing and perforation. By employing the surface-based cuttings analysis of this disclosure, two general datasets can be generated. First, surface-based cuttings analysis can provide an elemental / mineral dataset based on XRF and / or XRD data, and second, it can generate rock physical data. Elemental and mineral data can be obtained at the surface using surface-based cuttings analysis employing XRF and / or XRD. This dataset is equivalent to the downhole cable elemental / mineral dataset required for deploying downhole elemental logging tools. Based on the elemental and mineral data, models of the rock physical data can be adopted when combined with the cuttings data. Such rock physical data includes, for example, density, rock strength, sonic propagation time (the time difference of compressed sonic waves from sonic logging, hereinafter referred to as "DTC"), etc. Furthermore, according to some embodiments, surface-based cuttings analysis can be time-delay controlled, allowing depth data to be correlated with surface data. Ground-based cuttings analysis can provide calibration between elemental logging and cuttings / core samples, and can be used to develop 3D elemental mapping and / or cuttings-based modeling.

[0037] The implementation schemes described herein can be used to characterize formations and optimize drilling operations, drilling fluids, drill bit performance, and post-drilling operations. The surface-based cuttings analysis disclosed herein can provide rock physical data, including but not limited to unconfined compressive strength, rock density, cuttings gamma, time to sound propagation (DTC), total organic matter concentration (TOC index), brittleness index, mobile hydrocarbon index, and wellbore index.

[0038] Due to the XRF and XRD techniques and processes used to analyze samples, the elements and minerals tested from a single cuttings sample may vary at different testing times. Furthermore, different equipment used to test a single sample can yield different elements and minerals. Therefore, under previous systems and processes, data cannot be normalized to well data to enable the construction of geological models. For example, in some cases, three different types of XRF / XRD instruments may be used in a single drilling site. Even applying multiple different instruments to a single test sample may yield different values ​​(potentially large biases). Therefore, downhole analysis can be performed using wireline tools, which can potentially eliminate such differences in surface-based data. Wireline elemental logging tools can be used for downhole data collection. However, there may be high costs associated with operating such downhole wireline tools (economically and / or with wellbore risk).

[0039] Implementations of this disclosure relate to using a surface-based system to generate data similar to downhole / cableway data. That is, using high-resolution and highly accurate surface-based data to output information that is typically and historically only obtained using downhole (cableway) tools. Such data is directly and accurately correlated with depth compared to cableway datasets and / or logging-while-drilling datasets, providing additional comparability and feasibility.

[0040] Turn now Figure 2 The diagram illustrates a process 200 according to an embodiment of this disclosure. Process 200 describes a procedure for extracting multiple different formation and downhole properties, characteristics, and / or parameters from analysis of drill cuttings obtained at a surface location during drilling operations. Process 200 is used to extract additional information at the surface (surface logging), including one or more rock physical properties as described herein.

[0041] At box 202, drilling cuttings are obtained or collected. Drilling cuttings are obtained at the surface location during drilling operations. Cuttings can be obtained from circulating or pumped drilling fluid, which is pumped downhole to drive the operation of cutting tools (e.g., drill bits) and flows back to the surface through the annulus of the borehole. Cuttings are formation or earth material cut by the cutting tools and removed by the fluid flow of drilling fluid. Therefore, the returning or circulating drilling fluid will contain suspended material and cuttings when it circulates back to the surface.

[0042] At box 204, one or more types of sample tests can be used to test samples of the collected drilling cuttings. For example, according to embodiments of this disclosure, cuttings analysis can be performed using a single ground-based XRF tool (x-ray fluorescence) or a combination of a ground-based XRF tool and a ground-based XRD (x-ray diffraction) tool. The sample tests completed at box 204 generate the first input to the workflow.

[0043] It should be noted that Procedure 200 is applicable and can be used on a single cuttings sample. That is, only one identical test is required to achieve the following data extraction and output regarding downhole rock properties. Multiple sampling and testing are not required to perform the steps of Procedure 200.

[0044] At box 206, a first output can be generated from the cuttings analysis (first input) in box 204. The first output is an elemental output or elemental information that can be obtained using XRF sample testing of drilling cuttings. The elemental data in box 206 can be obtained directly from XRF data using standard mineralogical data and calibration associated with the XRF instrument used.

[0045] At box 208, the sample test (first input) from box 204 can also generate a second output. The second output is a mineralogical output or mineral information from drill cuttings. The mineralogical output can be generated from sample tests using XRF or XRD equipment and is a combination of the sample test from box 204 and the elemental output from box 206. The mineralogical data in box 208 can be obtained using chemical knowledge and element-based mineralogical models from elemental wireline logging. According to some embodiments of this disclosure, the mineralogical output at box 208 can be based at least in part on the correlation between certain elements and certain minerals, and a correlation model can be used.

[0046] The correlation models for minerals are derived from cable elemental logging and / or laboratory-based XRD data. The presence of various minerals in a given sample can be attributed to the presence of one or more specific elements within that sample. Here are a few examples of such element-to-mineral derivation: Quartz is derived from silicon (Si) with a positive function. Feldspar is derived from sulfur (S). Calcite is derived from calcium (Ca). Dolomite is derived from magnesium (Mg). Pyrite is derived from barium (Ba). Kaolinite is a function of aluminum (Al) and potassium (K). Illite is a function of magnesium (Mg). Chlorite is a function of iron (Fe). Montmorillonite is a function of iron (Fe) and aluminum (Al).

[0047] During the analysis, the total mineral content will be equal to 100%. However, if the total is determined not to be 100%, then the total clay content is equal to 100% - quartz - feldspar - calcite - dolomite - pyrite. In the following text, coefficients A, B, C, and D are derived from local cable element logging, and therefore different coefficients may exist for different zones / regions or even different boreholes within the same oilfield. Thus, the correlation model can vary based on local cable element logging. However, example correlations between minerals and their corresponding elements are as follows:

[0048] Quartz = A 石英 *Si (1)

[0049] Feldspar = A 长石 *S 3 -B 长石 *S 2 +C 长石 *S+D 长石 (2)

[0050] Calcite = A 方解石 *Ca+B 方解石 (3)

[0051] Dolomite = A 白云石 *Mg+B 白云石 (4)

[0052] Kaolinite = A 高岭石*Al+B 高岭石 *K (5)

[0053] Pyrite = A 黄铁矿 *Ba+B 黄铁矿 *Ba+C 黄铁矿 (6)

[0054] Montmorillonite = -A 蒙皂石 *Fe+B 蒙皂石 *Al (7)

[0055] Chlorite = -A 绿泥石 *Fe 2 +B 绿泥石 *Fe (8)

[0056] illite = A 伊利石 *Mg+B 伊利石 (9)

[0057] At box 210, a third output can be calculated from the first output (elemental output). The third output is the cuttings gamma. The third output of the cuttings gamma can receive specific elemental data (e.g., uranium, potassium, and thorium) as input. The gamma output can be used to correct the well depth of all other data, thus ensuring surface-based depth-related data analysis.

[0058] The following formula can be used to obtain rock fragment gamma:

[0059]

[0060] Where GR 岩屑 It's the rock cuttings gamma output of frame 210, U ％ It is the percentage of uranium in the sample, U r It is elemental radiation from the uranium in the sample, Th ％ It is the percentage of thorium in the sample. r It is elemental radiation from thorium in the sample, K ％ It is the percentage of potassium in the sample, and K r This is the elemental radiation of potassium from the sample. Furthermore, in formula (10), A, B, and C are coefficients used to determine gamma from the rock cuttings data. Coefficients A, B, and C can be obtained from the correlation of core data. XRF data from the core can detect uranium (U) elemental radiation. r Thorium (Th) element radiation Th r And potassium (K) element radiation K r and the percentage within the core (U ％ ,Th ％ K ％ Data input from three test points can be entered into formula (10). The values ​​of coefficients A, B, and C can be derived from the three test points. Once the model is built, U％ ,Th ％ K ％ Laboratory-based values / inputs can be obtained from U ％ ,Th ％ K ％ This replaces data / values ​​based on rock cuttings. In this way, a model based on rock cuttings data can be implemented, and laboratory-based data can be removed from the considerations.

[0061] The third output (cuttings gamma) can be used to calculate the fourth output at box 212. The fourth output is a measurement of movable hydrocarbons (movable HC) based on cuttings. In addition to receiving the gamma data output from box 210, the determination of the fourth output may also include logging-while-drilling (LWD) gamma data. Cuttings gamma is always less than LWD gamma; the difference is that cuttings samples are dry and cleaned, containing no movable organic matter, while LWD gamma is total gamma.

[0062] The following relationship can be used to obtain mobile hydrocarbons (mobile HC):

[0063]

[0064] Where GR LWD It is based on the gamma output of logging-while-drilling data, and GR 岩屑 This is the gamma output from box 210. In some cases, for example, when GR... LWD It may be equal to or less than GR 岩屑 At that time, GR LWD If an invalid value is displayed as measured by a cable tool, the default value can be assumed to be "0". The comparison condition "IF" in the model can control the results to be valid.

[0065] At box 214, the third output (gamma output), the second output (mineralogical output), and the drilling input (box 216) are used for quality control and evaluation. The drilling input (box 216) may include: logging-while-drilling gamma information, penetration rate information, torque information, pumping rate information, etc. (i.e., data and information directly related to drilling operations and / or downhole data). Quality control (box 214) may determine the validity of data samples by comparing them with downhole information and / or correlate such outputs (first output, second output, third output, fourth output) with depth and / or depth intervals.

[0066] If it is determined that the data needs further refinement, process 200 will return to box 204 to obtain additional samples of drilling cuttings for testing.

[0067] However, if the data is determined to be sufficient and accurate at box 214, a fifth output can be generated at box 218. The fifth output is the mineral-based rock fragment density. The mineral-based rock fragment density can be obtained using the following formula:

[0068]

[0069] Where ρ 岩屑 Based on the rock fragment density of minerals, M1 is the amount of the first mineral in the sample, ρ1 is the density of the first mineral, M2 is the amount of the second mineral in the sample, ρ2 is the density of the second mineral, M3 is the amount of the third mineral in the sample, ρ3 is the density of the third mineral, and M... n It is the amount of the nth mineral in the sample, and ρ n It is the density of the nth mineral. In formula (3), the coefficient or constant A is a constant from 0 to 1. The constant A represents the material lost compared to 100% density from the core sample. Thus, the constant A is estimated through local experience and data, and may be based on local and / or regional stratigraphic data. For example, shale has a larger value than sandstone because rock material is more easily lost when cuttings samples are prepared from shale using mud logging. The constant A can also be determined based on core data and lithology. Typically, some material and / or minerals may be lost during cuttings sample preparation when using mud logging (e.g., due to washing and grinding), but using the constant A in formula (12) yields more accurate results for mineral-based cuttings density.

[0070] The fifth output (density) can be combined with mineralogical data (box 220) and acoustic data (box 222) to generate a sixth output at box 224. The sixth output is the cuttings-based overall DTC (compressed acoustic time-of-flight - acoustic logging from cuttings, in μs / ft). The cuttings-based overall DTC is a pseudo-value derived from density as input, implying that some material and / or minerals may be lost during cuttings sample preparation. The cuttings-based overall DTC represents the basic level of the DTC measured from cuttings. This cuttings-based overall DTC can later be recalibrated by local core data. The mineralogical data at box 220 can be a second input to process 200 and can be obtained using core (e.g., downhole) and / or laboratory-based data. The acoustic data at box 222 can be compressed acoustic data from cross-dipole wireline logging. Thus, downhole drilling data can be used in conjunction with the surface-based drilling cuttings data of this disclosure to generate additional outputs indicating downhole formation properties and characteristics.

[0071] Overall DTC based on cuttings can be partially based on mineralogical density data. The relationship between density and DTC from cross-dipole logging, density derived from minerals, and its use in correlation models are discussed.

[0072] DTC 整体 =(-DTC) 指数2 )*ρ 岩屑 *DTC指数3 +DTC 指数1 (13)

[0073] DTC 整体 It is the overall DTC, ρ 岩屑 It is the mineral-based rock fragment density from the fifth output (which can be calibrated based on core samples), and DTC 指数1 DTC 指数2 and DTC 指数3 The correlation model can be derived from cross-dipole logging. It should be understood that density can be obtained and / or derived from cross-dipole wireline logging. Thus, the relationship between density and DTC can be constructed from cross-dipole wireline logging. Therefore, an algorithm for DTC can be constructed using data from cross-dipole wireline logging. Mineral-based density, as input to the algorithm, generates the DTC. Mineral-based DTC is pseudo-values ​​and can be calibrated using core samples.

[0074] Furthermore, the fifth output (density) from box 218 and the second output (mineralogical output) from box 208 can be used to generate a seventh output at box 226. The seventh output is the borehole diameter index. The borehole diameter index (seventh output) can be based on mineralogical density and brittleness. Borehole diameter is closely related to density and brittleness because it represents the shape of the borehole, which is based on rock brittleness and rock density. The borehole diameter can be obtained based on the following formula:

[0075]

[0076] Where C 指数 It is the wellbore index, ρ 岩屑 It is based on the cuttings density of the mineral (from box 218), and B is brittleness. As used herein, the borehole diameter (e.g., the diameter along the length of the borehole) is the untreated borehole shape without reaming and tripping. Certain drilling operations may alter the original borehole shape (e.g., reaming, tripping, etc.). As used herein, the borehole diameter refers to the original borehole shape. The borehole shape is determined at least in part by rock strength (e.g., the harder the rock, the more intact the shape). Density plays an important role in rock strength, where density has a positive effect relative to rock strength. In addition, rock brittleness also plays a role in the borehole diameter. When the rock is more brittle, the borehole shape may be more intact because the formation may contain abundant quartz and carbonates, both of which are brittle minerals. Such minerals (quartz, carbonates) typically have relatively high densities. When drilling shale, the borehole shape may be smaller than the standard size because the rock is relatively soft, less brittle, and has a lower rock density. In view of this, Equation (14) is empirical.

[0077] The overall DTC obtained at box 224 generates an eighth output (overall porosity) at box 228 and a ninth output (unconfined compressive strength) at box 230.

[0078] The overall porosity based on rock cuttings (box 228) can be obtained from the overall DTC obtained at box 224 using the following formula:

[0079]

[0080] Where φ 整体 It refers to overall porosity, DTC 整体 The overall DTC based on rock cuttings was obtained at frame 224. ma It is a sonic logging reading in 100% conglomerate phosphorite and can be derived from core testing (e.g., typical sandstone DTC in localized sandstone formations). w It is a sonic logging reading in 100% water, and KCP is the compaction factor (fraction). For example, for sandstone, the compaction factor "KCP" is 0.38, which is a known value associated with sandstone.

[0081] Unconfined compressive strength (frame 230) can be obtained from the overall DTC obtained at frame 224 using the following formula:

[0082]

[0083] Where UCS is the unconfined compressive strength, and DTC is the compressive strength. 整体 The overall porosity based on rock cuttings is obtained at box 224, and A is the lithology code. The lithology code is a known value for various strata. For example, the lithology code for sandstone is 1.67.

[0084] Based on cuttings analysis using XRF and / or XRD of a single cuttings sample, up to nine different formation rock properties can be extracted from process 200. Thus, embodiments of this disclosure relate to broad-spectrum analysis of rock properties based on substantially real-time analysis of a single cuttings sample returned to the surface during drilling operations. No additional downhole tools are required, except to potentially validate and / or improve data accuracy. Furthermore, multiple separate samples are not required, thus enabling a relatively fast and secure mechanism for reliably generating rock physics data. That is, in a broad sense, embodiments of this disclosure enable the extraction of downhole rock properties from cuttings analysis, rather than relying on downhole analysis (e.g., cores, downhole cable tools, etc.).

[0085] Turn now Figure 3 The diagram illustrates process 300 according to an embodiment of this disclosure. Process 300 is used to generate... Figure 2The schematic flow of the above outputs in process 200 is shown. Specifically, process 300 shows the workflow for generating the fifth output (based on mineral cutting density) and the sixth output (based on the overall DTC of cuttings).

[0086] In box 302, elemental input data is obtained from a single rock cutting sample using XRF. In box 304, mineralogical input data is obtained from a single rock cutting sample using XRD.

[0087] At box 306, the elemental input data from box 302 and the mineralogical input data from box 304 are combined to generate the mineral-based rock fragment density as discussed above.

[0088] The mineral-based cuttings density generated at box 306 is combined with mineralogical data from core samples and / or laboratory data (box 308), compressed sonic data from cross-even sub-cable analysis (box 310), and overall density from cross-even sub-logs (box 312). The combined data can be used to output the overall cuttings-based DTC at box 314.

[0089] In process 300, we can assume that:

[0090]

[0091]

[0092] The overall DTC based on cuttings is a pseudo-value derived from the sum of pseudo densities from many minerals as input. This means that some minerals may be lost during the preparation of cuttings samples, resulting in the overall DTC based on cuttings being a pseudo-value. The overall DTC based on cuttings represents the baseline level of the DTC measured from cuttings. Subsequently, the overall DTC based on cuttings can be recalibrated using local core data. In equations (17) to (19), when n equals a large number, this means that more minerals can be derived from the elements, which means that the loss of material is minimal during the preparation of cuttings samples. Therefore, the results (density based on cuttings and overall DTC based on cuttings) may be closer to 100% of the true / actual DTC from cable or core data. However, it is difficult to achieve lossless results during sample preparation, so calibration from cable cross-dipole logging can be used to ensure that the cuttings-based data is accurate.

[0093] The outputs and data obtained through processes 200 and 300 above can inform downhole operators about the properties and physical characteristics of the downhole rock. Since the data can be obtained virtually in real time from drilling cuttings and is also available at the surface, real-time decision-making is possible.

[0094] For example, because the data is comparable to datasets typically associated with cable tools, but without requiring such tools, a faster and more efficient process is achieved. Models of downhole properties, parameters, and characteristics can be determined from the acquired data, and actions can be taken based on these models. For example, drill bit performance can be determined from the aforementioned analysis and processes. By gaining near real-time access to downhole rock properties, operators can select specific instruments and tools for use, and / or data output can be normalized during drilling operations.

[0095] Furthermore, as described above, the surface-based systems and processes described herein enable the augmentation of prior XRF / XRD datasets. Typically, XRF / XRD datasets are limited to elemental and / or mineral information. However, embodiments of this disclosure advantageously augment this data to enable the extraction of rock properties at the surface, compared to conventional cable (i.e., downhole) tools.

[0096] During execution, the above procedure employs XRF / XRD analysis of individual cuttings samples during active drilling operations. Cuttings can be sampled at the surface and the lag time relative to depth can be recorded. XRF / XRD analysis is performed at the well site to generate elemental and mineral assemblages. As mentioned above, additional information can be obtained from the elemental and mineral assemblages. Specifically, rock properties (e.g., rock physical properties) can be obtained or estimated from the XRF / XRD elemental / mineral data. Such data may include, but are not limited to, feldspar data, quartz data, total clay, brittleness, rock density, DTC, unconfined compressive strength, TOC index, etc.

[0097] Turn now Figure 4 A schematic diagram of a drilling system 400 configured to perform embodiments of the present disclosure is shown. The drilling system 400 includes a drill string 402 having a bottom hole assembly (BHA) 404 and a drill bit 406 at its ends. The drill string 402 and the attached components are configured to drill a borehole 408 through a formation 410. During drilling operations, drilling mud 412 is pumped downhole through the drill string 402 to the drill bit 406 to drive the operation of the drill bit 406. The drilling mud 412 flows through 406 and into the annulus 414 of the borehole 408, and flows back to the surface. The drilling mud 412 picks up material from the drilling operation and carries it to the surface (drill cuttings).

[0098] At the surface, a ground-based cuttings collection device 414 can be used to sample drilling mud 412 containing drilling cuttings. The ground-based cuttings collection device 414 can be configured to obtain individual cuttings samples. A cuttings analysis unit 416 is arranged to perform at least one of X-ray diffraction (XRD) and X-ray fluorescence (XRF) analysis on the individual drilling cuttings sample. As shown, the ground-based cuttings collection device 414 and the cuttings analysis unit 416 are shown as a single unit / component. In an alternative configuration, the ground-based cuttings collection device 414 and the cuttings analysis unit 416 can be separate and distinct units. For example, the cuttings analysis unit 416 can be a portable XRF system carried in the field to perform cuttings analysis as described herein. A processing system 418 communicates with one or both of the ground-based cuttings collection device 414 and the cuttings analysis unit 416. The processing system 418 can be configured to perform the processes described herein to enable the extraction of rock physical data from the cuttings at the surface. The processing system 418 may include a display for the active plotting and display of processed and extracted information, including rock physical data obtained according to embodiments of this disclosure. With active display provided, operators can proactively monitor drilling events and information during active drilling operations and make real-time decisions based on the displayed information. Drilling events are actual facts observable at the surface. As part of the information source according to embodiments of this disclosure, drilling events are important for field operators to verify corrections to data based on cuttings interpretation and to test whether cuttings data are consistent with actual events.

[0099] Turn now Figures 5A to 5D as well as Figures 6A to 6D Example graphs and data obtained from the above process, as used during drilling operations, are shown according to embodiments of this disclosure. Figure 5A Plot 500A is shown, which illustrates various rock physical data obtained as described above, in which... Figure 5B , Figure 5C , Figure 5D Enlarged detail curves 500B, 500C, and 500D are shown for portions of curve 500A. Curves 500A to 500D represent the first well and an example section at a depth of approximately 3725m to approximately 4050m. Figure 6A The graph 600A is shown, which illustrates various rock physical data obtained as described above, in which... Figure 6B , Figure 6C , Figure 6D Enlarged detail curves 600B, 600C, and 600D are shown for portions of curve 600A. Curves 600A to 600D represent the first well and an example section at a depth of approximately 4750 m to approximately 5250 m.

[0100] refer to Figures 5A to 5D as well as Figures 6A to 6D Plots 500D and 600B include data on depth plotted and correlated with various mineral content derivatives (e.g., calcite, total carbonate, pyrite, illite, montmorillonite, kaolinite, total clay, feldspar, quartz, and chlorite). Plots 500C and 600C include various petrophysical data on depth as obtained from the above process (e.g., rock density, DTC, brittleness, UCS, borehole diameter, TOC). Plots 500D and 600D include various drilling parameters on depth (e.g., ROP, RPM, cuttings gamma, RACE / RPCE, GR1CX, TGAS, and total vertical depth).

[0101] exist Figures 5A to 5D In plots 500A to 500D of C, certain events or markers are identified. For example, at marker 502, eyework cannot be performed; at marker 504, a brittle zone is identified, indicating that the formation is prone to fracturing; at marker 506, a landing is identified; at marker 508, a leak without cuttings return is identified; and at marker 510, a weak zone is identified. The identification of these points / events is based on the analysis of all aggregated data obtained as in the embodiments adopted from this disclosure.

[0102] exist Figures 6A to 6D In the graphs 600A to 600D, certain events or markers are identified. For example, at marker 602, a potential leak in a brittle zone is identified; at marker 604, a leak is identified; at marker 606, a tight tube event is identified; and at marker 608, a stall of the top drive is identified. The identification of these points / events is based on the analysis of all aggregated data obtained as from the embodiments adopted in this disclosure. The information provided at marker 604 indicates a drilling fluid leak, which may be caused by changes in the physical properties of the formation rocks. Furthermore, marker 608 shows why the top drive may have stalled. The data along marker 608 indicates that clay-filled fractures in a brittle zone may have caused the drill bit to fall into a "slot" or other natural fracture.

[0103] Graphs 500A to 500D and 600A to 600D illustrate values ​​from some embodiments of this disclosure, demonstrating the advantages of obtaining rock physical data during drilling operations. It should be noted that the graphs are generated in real-time or near real-time during drilling operations, and therefore the complete graphs shown are only available after drilling operations have exceeded the minimum indicated depth. As described above, highly specific events and analyses of such events can be readily determined in real-time or near real-time. With knowledge of the formation and rock properties at a given depth, such analyses allow for a significant reduction in rig or drilling operation downtime and can further improve drilling efficiency.

[0104] Graphs 500A to 500D and 600A to 600D can be displayed on a ground-based monitor (e.g., at the drilling rig or drilling site), allowing human operators to visually see the correspondence between proactive data collection and different datasets acquired during drilling operations. Compared to prior art systems, operators are able to make more informed decisions in real time based on this visualization. Furthermore, the amount of data that can be visualized can far exceed that of existing systems. In some embodiments, the collected data can be processed automatically, enabling real-time or near-real-time automated responses without human intervention. That is, because the datasets obtained from embodiments of this disclosure are extensive and include rock properties, automated processes can be based on proactively collected ground-based cuttings analysis. Such automated processes may include adjustments to drilling operations, including but not limited to changes in drilling pressure, penetration rate, revolutions per minute, stopping drilling, and / or triggering alarms to notify human operators of actions that can be taken based on the collected datasets.

[0105] The combination of elemental / mineral data and rock physical data can be displayed in depth-based logging using surface display equipment and can be analyzed similarly to wireline logging (but these are obtained at the surface and no wireline tools are running downhole). Furthermore, such data and information can be used for finite element analysis and modeling, reservoir navigation services and / or geosteering, bit performance and / or fracture modeling, and interval identification.

[0106] According to some embodiments of this disclosure, formation assessment techniques are provided that enable the construction of quantitative models of “sweetspot” fracturing zones for shale. Such “sweetspot” identification and modeling enables accurate and / or precise landings and the location of fracturing operations in the most promising or feasible zones along the borehole. As described above, quantitative data are obtained by measuring cuttings samples at the well site. Quantitative and initial data are XRF data acquired in the field during drilling operations. For example, a field-portable XRF system can be used to generate elemental and mineralogical assemblage data from one or more cuttings samples. Petrophysical data as described above can be obtained from this data.

[0107] Advantageously, according to some embodiments of this disclosure, relatively rapid analysis is provided to achieve enhanced reservoir navigation. For example, such enhanced reservoir navigation may include maintaining the well trajectory within a predefined optimal point fracture zone. Identifying optimal point fracture zones while drilling is an advantage of existing systems such as wireline systems. To achieve such enhanced reservoir navigation, embodiments of this disclosure provide accurate formation assessment information to keep the wellbore within the desired zone.

[0108] The embodiments of this disclosure enable the characterization of zones with carbonate, clay type, quartz, rock strength, and DTC in real time at the well site (i.e., during drilling operations). To assess the source rock, operators can use cuttings-based information obtained as described herein. For example, TOC index, mobile HC, Th / U, and cuttings-based inorganic gamma can be obtained in real time or near real time. Furthermore, to assess fracturing capability, operators can utilize cuttings-based petrophysical data obtained according to embodiments of this disclosure. For example, UCS—rock strength, DTC, brittleness, density, and mineralogical properties (such as quartz and clay type) can be derived according to embodiments of this disclosure, enabling the determination of fracturing capability. Clay type and its values ​​from cuttings-based XRF analysis can be used to optimize fracturing fluids via clay swelling and clay expansion analysis. These types of clay minerals are highly sensitive to fracturing fluids and therefore highly sensitive to effective permeability. Data generated during drilling can also be used during and after reaching total depth to generate optimized fracturing stages and perforation designs, thereby aiming to further maximize well productivity.

[0109] As discussed above, embodiments of this disclosure relate to an improved method for obtaining cable (downhole) data at the surface. Specifically, by using XRF / XRD to obtain surface-based data, additional downhole properties (e.g., rock physical properties) can be extracted to a level comparable to cable datasets. During drilling operations, individual cuttings samples can be obtained, and XRF and XRD analyses can be performed on them. Additional rock properties can be extracted from this information, thereby achieving a surface-based dataset similar to a cable dataset without the costs and risks associated with operating cable tools.

[0110] As described above, embodiments of this disclosure enable the definition of an "optimal point" within the formation for fracturing while drilling (e.g., shale gas). Furthermore, embodiments of this disclosure enable reservoir characterization to understand the causes of various drilling events. For example, collapses, losses, drilling defects, and higher-than-expected vibrations can all be identified from data obtained from embodiments of this disclosure. According to embodiments of this disclosure, data obtained while drilling at the surface can inform drilling operations to change how to drill or treat a given formation. For example, based on known downhole rock physical properties, as described herein, operators can make decisions regarding drill bit properties, adjust geosteering operations, etc. Additionally, knowledge of relatively difficult well sections and / or drilling locations can be provided, thus informing operators of risks and instructing them to perform drilling operations in a given manner.

[0111] Furthermore, the real-time or near real-time data acquisition provided by embodiments of this disclosure enables rapid and early / effective decision-making. For example, surface-based cuttings data analysis provided by embodiments of this disclosure can help operators refine models and understanding of reservoir characterization, as well as define potential causal maps of why certain drilling events may have occurred. These include higher or lower than expected vibrational stick-slip (VSS), damage to the cutting structure (e.g., drill bit), excessive wear, higher or lower than expected penetration rates, stuck pipe, etc. It should be understood that embodiments of this disclosure can eliminate the need to operate sonic LWD tools and / or prevent or avoid drilling in geomechanically challenging areas.

[0112] Although the embodiments described herein have been described with reference to specific accompanying drawings, it should be understood that various changes may be made and equivalents may be substituted for elements therein without departing from the scope of this disclosure. Furthermore, many modifications will be made to adapt particular apparatus, situations, or materials to the teachings of this disclosure without departing from the scope of this disclosure. Therefore, it is contemplated that this disclosure is not limited to the specific embodiments disclosed, but rather will include all embodiments falling within the scope of the following description of the appended claims or possible embodiments.

[0113] Implementation Scheme 1: A drilling process method comprising: performing a drilling operation through a downhole formation, the drilling operation generating drill cuttings; obtaining a single drill cuttings sample at a surface-based location; performing X-ray diffraction (XRD) and X-ray fluorescence (XRF) analysis on the single drill cuttings sample; obtaining elemental information of the single drill cuttings sample from the XRF analysis relating to the downhole formation; obtaining mineral information of the single drill cuttings sample from at least one of the XRD and XRF analyses relating to the downhole formation; and determining at least one petrophysical property of the downhole formation from the elemental information and the mineral information.

[0114] Implementation Scheme 2: The method according to any of the foregoing implementation schemes, wherein the at least one rock physical property includes one or more of the following: rock fragment gamma, rock fragment-based movable hydrocarbons, mineral-based rock fragment density, rock fragment-based overall DTC, wellbore index, rock fragment-based overall porosity, and unconfined compressive strength.

[0115] Implementation Scheme 3: The method according to any of the foregoing implementation schemes, wherein the at least one rock physical property includes rock fragment gamma obtained from: Where GR 岩屑 It is the rock fragment gamma, U ％ It is the percentage of uranium in this single drill cuttings sample, U r It is the elemental radiation of uranium from this single drill cuttings sample, Th ％ It is the percentage of thorium in this single drill cuttings sample. r It is the elemental radiation of thorium, K, from this single drill cuttings sample. ％ It is the percentage of potassium in this single drill cuttings sample, and K r The elemental radiation of potassium from this single drilling cuttings sample is used, and coefficients A, B, and C are obtained from the correlation of core data.

[0116] Implementation Scheme 4: The method according to any of the foregoing embodiments, wherein the at least one rock physical property includes rock fragment gamma and mobile hydrocarbons, wherein the mobile hydrocarbons are obtained by means of: mobile Where GR LWD It is based on the gamma output of logging-while-drilling data, and GR 岩屑 It is gamma from the rock fragments.

[0117] Implementation Scheme 5: The method according to any of the foregoing embodiments, wherein the at least one rock physical property includes the mineral-based rock fragment density obtained using: Where ρ 岩屑This refers to the mineral-based cuttings density, where M1 is the amount of the first mineral in a single drilling cuttings sample, ρ1 is the density of the first mineral, M2 is the amount of the second mineral in a single drilling cuttings sample, ρ2 is the density of the second mineral, M3 is the amount of the third mineral in a single drilling cuttings sample, and ρ3 is the density of the third mineral. n ρ is the amount of the nth mineral in a single drill cuttings sample. n Let A be the density of the nth mineral, and let A represent the material loss compared to 100% density.

[0118] Implementation Scheme 6: The method according to any of the foregoing implementation schemes, wherein the at least one rock physical property includes the use of the following chip-based overall DTC: DCT 整体 =(-DCT) 指数2 )*ρ 岩屑 *DTC 指数3 +DTC 指数1 DTC 整体 It is the overall DTC based on rock fragments, ρ 岩屑 It is based on the density of rock fragments from the minerals, and DTC 指数1 DTC 指数2 and DTC 指数3 Derived from a correlation model derived from cross-dipole logging.

[0119] Implementation Scheme 7: The method according to any of the foregoing implementation schemes, wherein the at least one rock physical property includes a wellbore index obtained using the following: Where C 指数 It is the wellbore index, ρ 岩屑 B is based on the density of rock fragments from the minerals, and B is the brittleness of the stratum.

[0120] Implementation Scheme 8: The method according to any of the foregoing implementation schemes, wherein the at least one rock physical property includes a cut-based overall porosity obtained using the following: φ 整体 = Where φ 整体 It refers to the overall porosity, DTC 整体 Based on the overall porosity of rock cuttings, DTC ma This is the sonic logging reading in 100% conglomerate phosphorite rock, DTC w It is a sonic logging reading in 100% water, and KCP is the compaction factor.

[0121] Implementation Scheme 9: The method according to any of the foregoing embodiments, wherein the at least one rock physical property includes unconfined compressive strength obtained from: Where UCS is the unconfined compressive strength, DTC is the overall porosity based on rock cuttings, and A is the lithology code.

[0122] Implementation Scheme 10: The method according to any of the foregoing implementation schemes, the method further includes: identifying fracturing sections of the formation based on the elemental information, the mineral information and the at least one rock physical property.

[0123] Implementation Scheme 11: The method according to any of the foregoing implementation schemes, the method further includes: identifying drilling events based on the elemental information, the mineral information and the at least one rock physical property.

[0124] Implementation Scheme 12: The method according to any of the preceding implementation schemes, wherein the drilling event is at least one of stuck drill bit and drill bit damage.

[0125] Implementation Scheme 13: A drilling system comprising: a drilling rig including a drill string having a drill bit at its end for drilling a borehole through a formation; a surface-based cuttings collection device configured to obtain a single drilling cuttings sample; a cuttings analysis unit for performing at least one of X-ray diffraction (XRD) and X-ray fluorescence (XRF) analysis on the single drilling cuttings sample; and a processing system configured to: obtain elemental information of the single drilling cuttings sample from the XRF analysis relating to the downhole formation; obtain mineral information of the single drilling cuttings sample from at least one of the XRD and XRF analyses relating to the downhole formation; and determine at least one petrophysical property of the downhole formation from the elemental information and the mineral information.

[0126] Implementation Scheme 14: The system according to any of the foregoing implementation schemes, wherein the at least one rock physical property includes one or more of the following: rock fragment gamma, rock fragment-based movable hydrocarbons, mineral-based rock fragment density, rock fragment-based overall DTC, wellbore index, rock fragment-based overall porosity, and unconfined compressive strength.

[0127] Implementation Scheme 15: A system according to any of the foregoing embodiments, wherein the at least one rock physical property includes rock fragment gamma obtained from: Where GR 岩屑 It is the rock fragment gamma, U ％ It is the percentage of uranium in this single drill cuttings sample, U r It is the elemental radiation of uranium from this single drill cuttings sample, Th ％ It is the percentage of thorium in this single drill cuttings sample. r It is the elemental radiation of thorium, K, from this single drill cuttings sample. ％It is the percentage of potassium in this single drill cuttings sample, and K r The elemental radiation of potassium from this single drilling cuttings sample is used, and coefficients A, B, and C are obtained from the correlation of core data.

[0128] Implementation Scheme 16: A system according to any of the foregoing embodiments, wherein the at least one rock physical property includes rock fragment gamma and mobile hydrocarbons, wherein the mobile hydrocarbons are obtained by means of: mobile Where GR LWD It is based on the gamma output of logging-while-drilling data, and GR 岩屑 It is gamma from the rock fragments.

[0129] Implementation Scheme 17: A system according to any of the foregoing embodiments, wherein the at least one rock physical property includes mineral-based rock fragment density obtained using the following: Where ρ 岩屑 This refers to the mineral-based cuttings density, where M1 is the amount of the first mineral in a single drilling cuttings sample, ρ1 is the density of the first mineral, M2 is the amount of the second mineral in a single drilling cuttings sample, ρ2 is the density of the second mineral, M3 is the amount of the third mineral in a single drilling cuttings sample, and ρ3 is the density of the third mineral. n ρ is the amount of the nth mineral in a single drill cuttings sample. n Let A be the density of the nth mineral, and let A represent the material loss compared to 100% density.

[0130] Implementation Scheme 18: A system according to any of the foregoing embodiments, wherein the at least one rock physical property includes a cut-based overall DTC obtained using the following: DCT 整体 =(-DCT) 指数2 )*ρ 岩屑 *DTC 指数3 +DTC 指数1 DTC 整体 It is the overall DTC based on rock fragments, ρ 岩屑 It is based on the density of rock fragments from the minerals, and DTC 指数1 DTC 指数2 and DTC 指数3 Derived from a correlation model derived from cross-dipole logging.

[0131] Implementation Scheme 19: The system according to any of the foregoing implementation schemes, wherein the at least one rock physical property includes a wellbore index obtained using the following: Where C 指数 It is the wellbore index, ρ 岩屑 B is based on the density of rock fragments from the minerals, and B is the brittleness of the stratum.

[0132] Implementation Scheme 20: A system according to any of the foregoing embodiments, wherein the at least one rock physical property includes a cut-based overall porosity obtained using the following: Where φ 整体 It refers to the overall porosity, DTC 整体 Based on the overall porosity of rock cuttings, DTC ma Includes sonic logging readings in 100% conglomerate phosphorite rock, DTC w It is a sonic logging reading in 100% water, and KCP is the compaction factor.

[0133] Implementation Scheme 21: The system according to any of the foregoing embodiments, wherein the at least one rock physical property includes unconfined compressive strength obtained from: Where UCS is the unconfined compressive strength, and DTC is the compressive strength. 整体 It is based on the overall porosity of rock cuttings, and A is the lithology code.

[0134] To support the teachings herein, various analytical components, including digital and / or analog systems, may be used. For example, controllers, computer processing systems, and / or geological guidance systems as provided herein and / or used with the embodiments described herein may include digital and / or analog systems. These systems may have components such as processors, storage media, memories, inputs, outputs, communication links (e.g., wired, wireless, optical, or others), user interfaces, software programs, signal processors (e.g., digital or analog), and other such components (e.g., resistors, capacitors, inductors, etc.) for providing operation and analysis of the apparatus and methods disclosed herein in any of several manners well known in the art. It may be understood that these teachings may be implemented, but not necessarily, in conjunction with a set of computer-executable instructions stored on a non-transitory computer-readable medium, including memory (e.g., ROM, RAM), optical media (e.g., CD-ROM), or magnetic media (e.g., disk, hard disk drive), or any other type of media, which, when executed, cause a computer to perform the methods and / or processes described herein. In addition to the functions described in this disclosure, these instructions may also provide equipment operation, control, data collection, analysis, and other functions that system designers, owners, users, or other such persons deem relevant. Processed data (such as the results of implemented methods) may be transmitted as signals via the processor output interface to a signal receiving device. The signal receiving device may be a display monitor or printer used to present the results to the user. Alternatively or otherwise, the signal receiving device may be a memory or storage medium. It should be understood that storing the results in memory or storage medium allows the memory or storage medium to be converted from a previous state (i.e., without results) to a new state (i.e., containing results). Furthermore, in some embodiments, if the results exceed a threshold, an alarm signal may be emitted from the processor to the user interface.

[0135] In addition, various other components may be included, and they may be required to provide aspects of the teachings herein. For example, sensors, transmitters, receivers, transceivers, antennas, controllers, optical units, electrical units, and / or electromechanical units may be included to support the aspects discussed herein or to support other functions beyond this disclosure.

[0136] In the context of describing the invention (particularly in the context of the appended claims), the terms “an,” “a,” and “the,” and similar designations, should be interpreted to cover both the singular and plural, unless otherwise specified herein or clearly contradicted by the context. Furthermore, it should be noted that the terms “first,” “second,” etc., used herein do not indicate any order, quantity, or importance, but are used to distinguish one element from another. The modifier “about,” used in conjunction with quantity, includes the stated value and has a meaning determined by the context (e.g., it includes the degree of error associated with a particular quantity of measurement).

[0137] It should be recognized that various components or technologies may provide certain necessary or beneficial functions or features. Therefore, these functions and features that may be required to support the appended claims and their variations are considered to be inherently included as part of the teachings herein and as part of this disclosure.

[0138] The teachings of this disclosure can be applied to a variety of well operations. These operations may involve treating a formation, fluids residing in the formation, boreholes, and / or equipment in the borehole, such as production tubing, with one or more treatment agents. Treatment agents can be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Exemplary treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, corrosion inhibitors, binders, permeability modifiers, drilling mud, emulsifiers, demulsifiers, tracers, flow improvers, etc. Exemplary well operations include, but are not limited to, hydraulic fracturing, production enhancement, tracer injection, cleaning, acidizing, steam injection, water injection, cementing, etc.

[0139] While the embodiments described herein have been described with reference to various implementations, it should be understood that various changes may be made and equivalents may be substituted for elements therein without departing from the scope of this disclosure. Furthermore, many modifications will be made to adapt particular apparatus, situations, or materials to the teachings of this disclosure without departing from the scope of this disclosure. Therefore, it is contemplated that this disclosure is not limited to the specific embodiments disclosed as the best mode contemplated for achieving the described features, but rather that this disclosure will include all embodiments falling within the scope of the appended claims.

[0140] Therefore, the embodiments disclosed herein should not be considered as limited by the foregoing description, but only by the scope of the appended claims.

Claims

1. A drilling process method, the drilling process method comprising: Drilling operations are performed through the downhole formation, and the drilling operations generate drilling cuttings at the bottom layer of the well. Obtain drilling cuttings samples at ground-based locations; At least one of X-ray diffraction (XRD) analysis and X-ray fluorescence (XRF) analysis was performed on the drilling cuttings samples. Elemental information of the drilling cuttings sample is obtained from at least one of the XRD analysis and the XRF analysis; Mineral information of the drill cuttings sample is obtained from at least one of the XRD analysis and the XRF analysis; The elemental and mineral information is used to determine the mineral-based rock fragment density; and The overall acoustic propagation time (DTC) based on rock fragments was determined using the determined mineral-based rock fragment density. The mineral-based rock fragment density is obtained using the following method: Where ρ 岩屑 M1 is the amount of the first mineral in the drilling cuttings sample, ρ1 is the density of the first mineral, M2 is the amount of the second mineral in the drilling cuttings sample, ρ2 is the density of the second mineral, M3 is the amount of the third mineral in the drilling cuttings sample, and ρ3 is the density of the third mineral. n ρ is the amount of the nth mineral in the drill cuttings sample. n Let A be the density of the nth mineral, and A be a constant between 0 and 1. The overall sound wave propagation time based on rock cuttings is obtained using the following method: DTC 整体 It is the overall DTC based on rock cuttings, ρ 岩屑 It is based on the density of rock fragments from the minerals, and DTC 指数1 DTC 指数2 and DTC 指数3 Derived from a correlation model derived from cross-dipole logging.

2. The method of claim 1, further comprising determining the overall porosity based on rock cuttings using the determined overall acoustic propagation time based on rock cuttings.

3. The method of claim 1, wherein the method further comprises determining the rock fragment gamma using the elemental information, and determining the rock fragment-based mobile hydrocarbons using the determined rock fragment gamma, wherein the rock fragment gamma is obtained by: Where GR 岩屑 It is the rock fragment gamma, U % It is the percentage of uranium in the drill cuttings sample, U r It is the elemental radiation of uranium from the drill cuttings sample, Th % It is the percentage of thorium in the drill cuttings sample. r It is the elemental radiation of thorium, K, from the drill cuttings sample. % It is the percentage of potassium in the drill cuttings sample, K r The elemental radiation of potassium from the drill cuttings sample is used, and the coefficients A, B, and C are obtained from the correlation of the core data.

4. The method of claim 3, wherein the rock-cut-based mobile hydrocarbon HC can be obtained using the following: Where GR LWD It is based on the gamma output of logging-while-drilling data, and GR 岩屑 It is the aforementioned rock fragment gamma.

5. The method of claim 1, further comprising determining a wellbore index using the mineral-based cuttings density, wherein the wellbore index is obtained using the following: Where C 指数 It is the wellbore index, ρ 岩屑 B is based on the density of rock fragments from the minerals, and B is the brittleness of the formation.

6. The method of claim 2, wherein the overall porosity based on rock cuttings is obtained using the following: in It is the overall porosity based on rock cuttings, DTC 整体 Based on the overall acoustic propagation time of rock cuttings, DTC ma It is the sound wave propagation time of 100% conglomerate phosphorite, DTC w It is the sound wave propagation time of 100% water, and KCP is the compaction factor.

7. The method of claim 1, further comprising determining the unconfined compressive strength using the overall acoustic propagation time based on rock cuttings, wherein the unconfined compressive strength is obtained from: in It is the unconfined compressive strength, DTC 整体 It is based on the overall acoustic propagation time of rock cuttings, and A is the lithology code.

8. The method according to claim 1, wherein the method further comprises: Fracturing zones in a formation are identified based on at least one of the mineral-based rock fragment density and the overall acoustic propagation time of the rock fragments.

9. The method according to claim 1, wherein the method further comprises: Drilling events are identified based on at least one of the mineral-based cuttings density and the overall acoustic propagation time of the cuttings.

10. The method of claim 9, wherein the drilling event is at least one of stuck drill bit and drill bit damage.

11. A drilling system, the drilling system comprising: A drilling rig, the drilling rig including a drill string having a drill bit at its end for drilling a borehole through a downhole formation; A ground-based cuttings collection device, configured to obtain drilling cuttings samples from the downhole layer; A cuttings analysis unit, wherein the cuttings analysis unit is used to perform at least one of X-ray diffraction (XRD) analysis and X-ray fluorescence (XRF) analysis on the drilling cuttings sample; and Processing system, the processing system being configured to: Elemental information of the drilling cuttings sample is obtained from at least one of the XRD analysis and the XRF analysis; Mineral information of the drill cuttings sample is obtained from at least one of the XRD analysis and the XRF analysis; The elemental and mineral information is used to determine the mineral-based rock fragment density; and The overall sound wave propagation time based on rock fragments was determined using the determined mineral-based rock fragment density. The overall sound wave propagation time based on rock cuttings is obtained using the following formula: DTC 整体 It is the overall DTC based on rock cuttings, ρ 岩屑 It is based on the density of rock fragments from the minerals, and DTC 指数1 DTC 指数2 and DTC 指数3 Derived from the correlation model from cross-dipole logging, The mineral-based rock fragment density is obtained using the following method: Where ρ 岩屑 M1 is the amount of the first mineral in the drilling cuttings sample, ρ1 is the density of the first mineral, M2 is the amount of the second mineral in the drilling cuttings sample, ρ2 is the density of the second mineral, M3 is the amount of the third mineral in the drilling cuttings sample, and ρ3 is the density of the third mineral. n ρ is the amount of the nth mineral in the drill cuttings sample. n Let A be the density of the nth mineral, and let A be a constant between 0 and 1.

12. The system of claim 11, wherein the processing system is further configured to determine the overall porosity based on rock cuttings using the determined overall acoustic propagation time based on rock cuttings.

13. The system of claim 11, wherein the processing system is further configured to determine a wellbore index using the mineral-based cuttings density, wherein the wellbore index is obtained using: Where C 指数 It is the wellbore index, ρ 岩屑 B is the mineral-based rock cutting density, and B is the brittleness of the downhole formation.

14. The system of claim 12, wherein the overall porosity based on rock cuttings is obtained using the following: in It is the overall porosity based on rock cuttings, DTC 整体 Based on the overall acoustic propagation time of rock cuttings, DTC ma It is the sound wave propagation time of 100% conglomerate phosphorite, DTC w It is the sound wave propagation time of 100% water, and KCP is the compaction factor.

15. The system of claim 11, wherein the processing system is further configured to determine the unconfined compressive strength using the overall acoustic propagation time based on rock cuttings, wherein the unconfined compressive strength is obtained from: in It is the unconfined compressive strength, DTC 整体 It is based on the overall acoustic propagation time of rock cuttings, and A is the lithology code.

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