Systems and methods for discovery and recovery of underground fluids and verification of underground storage fluids - Patents.com

Abstract

Embodiments of the present invention relate to methods, systems, and software for identifying and quantifying hydrogen, helium, carbon dioxide, or other fluids underground using multiple indicators from geophysical well log logs, other wireline logging tools, or mud logging tools.

Description

[Technical field]

[0001] (CROSS REFERENCE TO RELATED APPLICATIONS) This application claims priority to U.S. Provisional Application No. 63 / 325,094, filed March 29, 2022, the disclosure of which is incorporated by reference in its entirety herein. [Background technology]

[0002] Subterranean rock formations have pores within them. The pores, or pore space, are defined by the rock matrix of the rock formation and can hold any of a variety of fluids, such as hydrocarbons, water, hydrogen, carbon dioxide, helium, etc. If the porosity of a subterranean rock formation is large enough, the subterranean rock formation may contain a reservoir of fluid. Such a reservoir can be accessed to extract the fluid therein.

[0003] There are many existing wells throughout the world that extend into underground rock formations. For many of these wells, well logs are available that contain information about the geophysical properties of the rock matrix and its contents. However, many of these well logs focus on the discovery of only one type of fluid, such as oil. Summary of the Invention [Means for solving the problem]

[0004] Embodiments of the present invention relate to methods, systems, and software for identifying and quantifying hydrogen, helium, carbon dioxide, or other fluids underground using multiple indicators from geophysical well log logs, other wireline logging tools, or mud logging tools.

[0005] In one embodiment, a method of identifying subterranean fluids in a geological formation is disclosed. The method includes determining a rock matrix type of a rock formation in a geological region of interest. The method includes determining a porosity of the rock formation. The method includes determining a fluid density of a fluid in a pore space of the rock formation. The method includes determining an acoustic slowness of the fluid in the pore space. The method includes determining a fluid type of the fluid in the pore space.

[0006] In one embodiment, a system for identifying subterranean fluids in a geological formation is disclosed. The system includes a computing device having a processor and a memory storage device operatively coupled to the processor, the memory storage device having one or more operating programs including machine-readable and executable instructions for identifying one or more selected fluids in a pore space of a rock formation based on data from one or more well log logs, the processor configured to read and execute the one or more operating programs. The data from the one or more well log logs indicates one or more of a rock matrix type of the rock formation, a fluid density of the fluids in the pore space, or an acoustic slowness of the fluids in the pore space.

[0007] In one embodiment, a method of identifying subterranean fluids in a geological formation is disclosed. The method includes identifying a geological region of interest. The method includes determining a rock matrix type of a rock formation in the geological region of interest. The method includes determining a porosity of the rock formation. The method includes determining a fluid density of a fluid in a pore space of the rock formation. The method includes determining an acoustic slowness of the fluid in the pore space. The method includes determining a fluid type of the fluid in the pore space. The method includes flagging the presence of a selected fluid type.

[0008] In one embodiment, a method for distinguishing hydrogen from other subsurface fluids is disclosed. The method includes using acoustic well geophysical logs to distinguish hydrogen from hydrocarbon fluids or other subsurface fluids. The method includes using density well geophysical logs to distinguish hydrogen from water.

[0009] In one embodiment, a method for distinguishing carbon dioxide from other subsurface fluids is disclosed. The method includes distinguishing carbon dioxide from hydrocarbon fluids or other subsurface fluids using acoustic geophysical logs. The method includes distinguishing carbon dioxide from water using density geophysical logs.

[0010] In one embodiment, a method for distinguishing hydrogen injected underground from other underground fluids is disclosed. The method includes using acoustic well geophysical logs to distinguish hydrogen obtained from various industrial sources from hydrocarbon fluids or other underground fluids. The method includes using density well geophysical logs to distinguish hydrogen obtained from various industrial sources from water.

[0011] In one embodiment, a method is disclosed for distinguishing carbon dioxide injected underground in a gaseous or supercritical state from other subsurface fluids. The method includes using acoustic geophysical logs to distinguish carbon dioxide obtained from various industrial sources from hydrocarbon fluids or other subsurface fluids. The method includes using density geophysical logs to distinguish carbon dioxide obtained from various industrial sources from water.

[0012] In one embodiment, a method for identifying and quantifying hydrogen in a subterranean formation is disclosed that includes using geophysical logs, including one or more of acoustic or density logs, to identify and quantify hydrogen in a subterranean formation.

[0013] In one embodiment, a method of identifying and quantifying carbon dioxide in a subsurface formation is disclosed, the method comprising identifying and quantifying subsurface carbon dioxide using geophysical logs, including one or more of acoustic logs or density logs.

[0014] In one embodiment, a method for identifying and quantifying helium in a subsurface formation is disclosed that includes using geophysical logs, including one or more of acoustic logs or density logs, to identify and quantify helium in the subsurface.

[0015] In one embodiment, a method of exploring for hydrogen in a subterranean formation is disclosed, the method comprising using geophysical log patterns characteristic of hydrogen to identify accumulations of hydrogen in a subterranean formation.

[0016] In one embodiment, a method of exploring for carbon dioxide in a subterranean formation is disclosed, the method comprising identifying accumulations of carbon dioxide in a subterranean formation using geophysical log patterns characteristic of carbon dioxide.

[0017] In one embodiment, a method of exploring for helium in a subterranean formation is disclosed that includes identifying accumulations of helium in a subterranean formation using a geophysical log pattern characteristic of helium.

[0018] In one embodiment, a method for verifying storage of hydrogen in an underground reservoir is disclosed, the method comprising using a geophysical log pattern characteristic of hydrogen to identify accumulation of hydrogen in the underground reservoir.

[0019] In one embodiment, a method for verifying storage of carbon dioxide in an underground reservoir is disclosed, the method comprising identifying accumulation of carbon dioxide in the underground reservoir using a geophysical log pattern characteristic of carbon dioxide.

[0020] In one embodiment, a method for verifying carbon dioxide sequestration in subsurface minerals is disclosed, the method comprising identifying accumulations of carbon dioxide in subsurface minerals using geophysical log patterns characteristic of carbon dioxide.

[0021] In one embodiment, a computer-assisted method for distinguishing hydrogen from other subsurface fluids is disclosed. The method includes automatically distinguishing hydrogen from helium, nitrogen, carbon dioxide, or hydrocarbon fluids using a computational device and a sonic geophysical log. The method includes automatically distinguishing hydrogen from water using a geophysical density log.

[0022] In one embodiment, a computer-aided method for identifying and quantifying hydrogen in a subterranean geological formation is disclosed, the method including automatically using, by a computing device, geophysical logs, including one or more of acoustic logs or density logs, to identify and quantify hydrogen in the subterranean geological formation.

[0023] In one embodiment, a computer-aided method of exploring for hydrogen in a subterranean geological formation is disclosed that includes automatically identifying accumulations of hydrogen in a subterranean geological formation by a computing device using a computer-aided operating program configured to automatically use geophysical log patterns characteristic of hydrogen to search existing or archived well log geophysical logs for the presence of hydrogen in the subterranean geological formation.

[0024] In one embodiment, a computer-aided method for distinguishing carbon dioxide from other subsurface fluids is disclosed. The method includes automatically distinguishing, by a computing device, carbon dioxide from hydrocarbon fluids using acoustic well geophysical logs. The method includes automatically distinguishing, by a computing device, carbon dioxide from water using acoustic well geophysical logs.

[0025] In one embodiment, a computer-aided method for identifying and quantifying carbon dioxide in a subterranean formation is disclosed, the method including automatically using, by a computing device, geophysical logs, including one or more of acoustic logs or density logs, to identify and quantify carbon dioxide in the subterranean formation.

[0026] In one embodiment, a computer-aided machine learning method for exploring for carbon dioxide in the subsurface is disclosed. The method includes automatically using, by a computing device, geophysical log patterns characteristic of carbon dioxide to identify potential accumulations of carbon dioxide in the subsurface. The method includes automatically using, by the computing device, an operating program stored on the computing device to search the geophysical well logs for the presence of existing or stored carbon dioxide.

[0027] In one embodiment, a computer-aided method for distinguishing helium from other subsurface fluids is disclosed. The method includes automatically distinguishing, by a computing device, helium from hydrocarbon fluids using sonic well geophysical logs. The method includes automatically distinguishing, by a computing device, helium from water using sonic well geophysical logs.

[0028] In one embodiment, a computer-aided method for identifying and quantifying helium in a subterranean geological formation is disclosed, the method including automatically using, by a computing device, geophysical logging logs, including one or more of acoustic logging logs or density logging logs, to identify and quantify helium in the subterranean geological formation.

[0029] In one embodiment, a computer-aided machine learning method for exploration of helium in the subsurface is disclosed. The method includes automatically using, by a computing device, geophysical log patterns characteristic of helium to identify potential accumulations of helium in the subsurface. The method includes automatically using, by the computing device, an operating program stored on the computing device to search existing or stored well geophysical logs for the presence of helium.

[0030] In one embodiment, a method for identifying subsurface hydrogen, helium, or carbon dioxide is disclosed. The method includes using an image recognition module to automatically analyze geophysical or borehole images for patterns characteristic of subsurface hydrogen, helium, or carbon dioxide to identify subsurface accumulations of hydrogen, helium, or carbon dioxide. The method includes outputting results of the analysis of the geophysical log images.

[0031] In one embodiment, a method for identifying subsurface hydrogen, helium, or carbon dioxide is disclosed. The method includes receiving information related to an imaged or digitized well log, the information including a well log characteristic. The method includes estimating a likelihood that the well log characteristic is indicative of a subsurface accumulation of hydrogen, helium, or carbon dioxide. The method includes determining whether the estimated likelihood meets a predetermined threshold for the likelihood of the presence of a subsurface accumulation of hydrogen, helium, or carbon dioxide. In response to determining whether the estimated likelihood meets the predetermined threshold, the method includes outputting an indication that the well log characteristic is indicative of the presence or not of a subsurface accumulation of hydrogen, helium, or carbon dioxide.

[0032] Any feature of the disclosed embodiments may be used in combination with each other without limitation.In addition, other features and advantages of the present disclosure will become apparent to those skilled in the art upon consideration of the following detailed description and the accompanying drawings. [Brief description of the drawings]

[0033] For better understanding, like reference numerals are used to refer to like elements throughout the various accompanying drawings. These drawings are to be understood as merely illustrating exemplary embodiments of the present invention and are not intended to limit the scope of the invention. Embodiments of the present invention will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0034] [Figure 1] 1 is a flowchart of a method for identifying a particular fluid in a geological formation, according to an embodiment. [Figure 2A] The predicted density well log response over a range of assumed sandstone matrix porosities is plotted for different end-member gases. [Figure 2B] The predicted density log response over a range of assumed gabbro matrix porosity is plotted for different end-member gases. [Figure 3A] The acoustic well log response over a range of assumed sandstone matrix porosities is plotted for different end-member gases. [Figure 3B] The acoustic well log response over a range of assumed gabbro matrix porosity is plotted for different end-member gases. [Figure 4] 1 is a synthetic well log showing bulk density and acoustic slowness response across a range of porosities and fluid compositions in an embodiment; [Diagram 5] FIG. 5 is a block diagram of a system 500 for implementing the methods disclosed herein, according to an embodiment. [Figure 6] FIG. 6 is a block diagram of an image analysis method 600 according to an embodiment. [Figure 7A] 1 is a flow diagram of analysis of a geological map and corresponding well log in an embodiment; [Figure 7B] 1 is a flow diagram of analysis of a geological map and corresponding well log in an embodiment; [Figure 8] 1 shows wireline well log data showing gamma ray and caliper measurements from a well. [Figure 9] 9 shows wireline logging log data showing resistivity measurements from the well of FIG. 8. [Figure 10] FIG. 8 shows wireline well log data showing slowness, gradient, bulk density, and neutron porosity measurements from the well. [Figure 11]Figure 8 shows a mud gas mass spectral logging log from a recently drilled well targeting the hydrogen-rich reservoir in the well. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0035] Embodiments of the present invention relate to methods, systems, and software for identifying and quantifying hydrogen, helium, carbon dioxide, or other fluids underground using multiple indicators from geophysical well logs, other wireline logging tools, or mud logging tools. The methods, systems, and software can be used to explore for the presence of hydrogen, helium, carbon dioxide, or other subsurface gases, monitor or quantify the storage of these gases underground, track carbon dioxide during storage or enhanced oil recovery, and evaluate and quantify carbon sequestration from underground mineralization. The methods, systems, and software disclosed herein can determine the presence or quantify the presence of hydrogen, helium, carbon dioxide, or other fluids underground using relationships between density and acoustic properties in different rock and fluid types that can be evaluated using visual inspection, core analysis, borehole images, quantitative analysis, and supervised or unsupervised computer-aided machine learning.

[0036] FIG. 1 is a flow chart of a method 100 for identifying a particular fluid in a geological formation, according to an embodiment. The method 100 includes steps of identifying a geological region of interest, block 110, determining a rock matrix type of a rock formation in the geological region of interest, block 120, determining a porosity of the rock formation, block 130, determining a fluid density of a fluid in a pore space of the rock formation, block 160, determining an acoustic slowness of the fluid in the pore space, block 170, determining a fluid type of the fluid in the pore space, and block 180, flagging a determination of a selected fluid type. One or more of these blocks 110-180 may be combined, omitted, or divided into multiple blocks according to an embodiment. For example, the method 100 may not include any block 140, or may combine blocks 150 and 160 into a single block. As described in more detail below, in some embodiments, additional blocks may be added to the method 100.

[0037] The method 100 described above is used to resolve fluid properties such as density and acoustic slowness from geophysical well logs, which identifies specific fluids such as hydrogen, helium, carbon dioxide, or natural gas in the formation. The method 100 is used to identify and quantify different subsurface fluids such as hydrogen, helium, carbon dioxide, natural gas, or other fluids in the formation. Additionally, the method 100 can also be used to determine the relative amount of fluid. Determining the relative amount of fluid in the pore space is accomplished by using the Δt calculated by the method 100. fluid This can be achieved by comparing the acoustic slowness of one or more subsurface fluid combinations.

[0038] Identifying the geological region of interest in block 110 may include selecting a geological location including one or more of vertical and lateral locations, depths (e.g., one or more subsurface sections), etc. The geological region of interest may include one or more wells, such as a field.

[0039] At block 110, a geological region of interest is identified. Input to a computer program may be used to identify the geological region of interest. Identifying the geological region of interest at block 110 may include selecting, accessing, or examining one or more geophysical well logs that correspond to the geological region of interest.

[0040] The process of determining rock matrix type of a rock formation in a geological region of interest, block 120, may include determining the rock matrix type in one or more subsurface sections of the rock formation. Determining the rock matrix type may include examining one or more well geophysical logs, such as automatically performed by a computing device. The information in the well log logs may include the rock matrix type or one or more characteristics associated therewith. For example, the rock matrix type may be indicated in an image log, resistivity, gamma ray measurements, etc. Such data may be located in well geophysical logs (including image log logs) and identified and retrieved by an image processing program stored within the computing device.

[0041] Determination of the rock matrix type of rock formations in a geological region of interest can be accomplished using available records for the geological region of interest, including well geophysical logs (e.g., gamma ray logs and / or geopotential logs), or, if cuttings or cores are recovered from the subsurface, other means of evaluation of the subsurface formations (e.g., mud logs, visual inspection of cuttings or cores, mineralogical evaluation, x-ray diffraction, x-ray fluorescence, or other geochemical or optical measurements or processes). Such identification can be accomplished using computer-aided techniques or other techniques. For example, the rock matrix of a given subsurface interval can be interpreted from well geophysical logs and verified or cross-referenced with other means described herein.

[0042] Based on the rock matrix type, the rock matrix density can be determined or estimated. For example, known densities of some common subsurface materials are shown below in Table 1. The rock matrix density can be used to determine further properties of the rock formation and its contents.

[0043] In an embodiment, bulk density measurements from geophysical logging tools are derived from a combination of rock matrix density, pore fluid density, and the relative proportions of each therein. In rocks, pores may form due to the way particles settle during deposition, or secondary diagenetic processes such as chemical and mechanical weathering and fracturing, and pores may close due to compaction, cementation, or layer-parallel shortening. Water or brine (water with salt) fills the pore space initially in typical depositional processes, but water may be displaced by other fluids such as oil, natural gas, hydrogen, helium, or carbon dioxide as these fluids move through the subsurface rock. For a given porosity and rock matrix, bulk density measurements vary with the fluids that fill the pores. Water is denser than oil and natural gas, and hydrogen and helium are much less dense than other fluids that may be present in subsurface rocks.

[0044] Rock materials generally behave as insulators, and their high electrical conductivity measurements are usually due to the presence of pore fluids within them, often a combination of water and hydrocarbons or other gas species. Resistivity is the inverse of electrical conductivity and is a rock property measured to characterize formations. Resistivity of reservoir rocks can range over three orders of magnitude, from less than 10 Ω·m for shales to more than 1,000 Ω·m for dense limestones. Drilling fluids can infiltrate the formation during the drilling process, so multiple resistivity tools are needed to measure at different depths. The resistivity of deeper intact (unpenetrated) zones may be compared to shallower invaded zones that have been influenced by the drilling mud used (e.g., oil-based or water-based). Changes in resistivity may indicate changes in pore fluids (e.g., from water to hydrocarbons or other gases) or potentially changes in porosity or permeability. Data from resistivity logs may be used to calibrate other measurements or to determine a representative value (e.g., true density of unfractured / native lithology) that is nearly intact in a section of the wellbore.

[0045] Acoustic measurements from geophysical logging tools result from a combination of the speed of sound through the rock matrix, pore fluids, and the rock formations containing the relative proportions of these two components of the formation. This characteristic speed of sound is also expressed as interval transit time. Just as the speed of sound in air is different from the speed of sound in water, different rocks have different acoustic properties, as do the various fluids that fill the pore spaces of rocks. Natural gas (mainly methane) has a very slow interval transit time compared to other rock types present underground. Methane also has a much slower interval transit time than water, hydrogen, and helium. Meanwhile, hydrogen has an interval transit time similar to water, helium is about 30% slower than hydrogen and water, and methane and carbon dioxide (in gaseous or supercritical states) have much slower transit times than water.

[0046] Other geophysical well logs are used to determine subsurface properties, especially the geological properties of reservoirs. Downhole gamma ray tools measure natural radiation emitted by rocks (in API units), primarily due to radioactive decay of uranium, thorium, and potassium contained in the mineral matrix, and are useful for distinguishing between rock types. Carbonate rocks such as limestone and dolomite generally have low concentrations of these elements, resulting in low gamma ray readings. Shales often have relatively high uranium concentrations (e.g., 3-250 ppm), which are reflected in higher gamma ray readings. Sandstones often have concentrations of the above elements and show gamma ray readings intermediate to those of the two previous examples, varying depending on potassium from potassium feldspar mineral grains in the rock.

[0047] Determining the porosity of the rock formation in block 130 may include determining the porosity of the rock formation in one or more subsurface intervals in the geological region of interest. Determining the porosity of the rock formation in block 130 may include obtaining porosity data directly (e.g., field testing of the rock matrix) or from one or more geophysical well logs. For example, neutron porosity tools are useful geophysical well logs for characterizing the porosity of a rock formation by measuring the interaction of neutrons emitted from a radioactive source with the rock matrix and fluids contained in the pore space of the rock formation. As used herein, "pore space" includes the singular and plural meanings of pore space and pore spaces. For example, "pore space" includes the volume of pores defined by the rock matrix in the rock formation and may include fracture volume, spaces between rock particles, etc. Pore space may include multiple pore spaces that are interconnected (e.g., fluidly connected) throughout the rock formation. Imaging well logs may be evaluated to indicate rock integrity or to identify zones of intense fracture. Baseline formation properties (e.g., density or porosity) may be determined from log measurements collected in portions of the well (e.g., rock layers at discrete subsurface locations or intervals) that are shown to be intact via imaging well logs. Resistivity values ​​may also indicate locations where porosity is truly minimal in lithologies (e.g., igneous rocks) where density or neutron porosity well logs are not properly calibrated. Porosity is obtained directly or calculated from geophysical well log data for one or more subsurface intervals in the geological region of interest. For example, a computer program may identify and obtain one or more porosity values ​​of the rock matrix in the rock formation.

[0048] Determining the porosity of the rock formation in block 130 may include other assessment means such as microscopy, porosimetry, or geochemical measurements of the subsurface formation when drill cuttings or cores are recovered from the subsurface. These data provide input to the matrix density and porosity in Equations 1-2 below, examples of which are shown in Tables 1-3 below. These data are used to solve for the fluid density and acoustic slowness of the fluid in the pore space, as described in more detail below.

[0049] The porosity can be used to calculate the fluid acoustic and fluid density responses in Equation 1 and Equation 2 (below). To demonstrate the technique, commonly found rock types and fluid properties can be used in the calculations. Tables 1 and 2 show characteristic density properties and acoustic slowness values ​​for various rock and mineral types (e.g., sandstone, limestone, dolomite, gabbro, serpentine). Table 3 shows the acoustic slowness for various end-member fluids (water, hydrogen, helium, methane, nitrogen, carbon dioxide).

[0050] [Table 1]

[0051] [Table 2]

[0052] [Table 3]

[0053] The data in Tables 1-3 can be used to determine fluid density and acoustic slowness using Equation 1 and Equation 2 below. To demonstrate the technique, commonly found rock types and fluids are provided as hypothetical test scenarios. Tables 1 and 2 show characteristic density properties and acoustic slowness values ​​for various rock types and minerals (e.g., sandstone, limestone, dolomite, gabbro, serpentine). Table 3 shows the acoustic slowness of various end-member fluids (water, hydrogen, helium, methane, nitrogen, carbon dioxide). Assuming different porosity ratios, Equation 1 and Equation 2 can be used to calculate different results for well logging response.

[0054] Equations 1 and 2 below show the relationship between the measured density or acoustic log response and the density or acoustic properties of the rock matrix and pore fluid.

[0055] Equation 1 is Δt log =(Φ)*Δt fluid +(1-Φ)*Δt matrix where: Δt log = acoustic slowness (e.g., interval transit time measured by an acoustic logging tool) (μs / ft) Φ = porosity of the rock formation expressed as a ratio (e.g. 10% = 0.1) Δt fluid = acoustic slowness or interval transit time of a fluid contained in one or more pore spaces (μs / ft) 1-Φ = volume fraction of rock in the formation expressed as a ratio (e.g. 90% = 0.9) Δt matrix = Time required to pass through the rock matrix (μs / ft) It is.

[0056] Equation 1 expresses the acoustic logging response (Δt log ) is the ratio of the porosity of the rock layer (Φ) to the pore fluid transit time in the rock layer (Δt fluid is also called the acoustic slowness of the pore fluid), multiplied by the remaining volume fraction of the rock layer (1-Φ) and the interval transit time of the rock matrix (Δt matrix) is equal to the sum of the multiplications of the acoustic slowness of the fluid (Δt fluid ) can be rearranged to solve for the acoustic slowness (Δt fluid ) can later be used to identify fluids within the pore spaces within the rock matrix of a rock formation.

[0057] Equation 2 is ρ log =(Φ)*ρ fluid +(1-Φ)*ρ matrix where: ρ log = Bulk density (g / cm) measured by density logging tool 3 ) Φ = porosity of the rock formation expressed as a ratio (e.g. 10% = 0.1) ρ fluid = fluid density (g / cm) of the fluid contained in one or more pore spaces 3 ) 1-Φ = volume fraction of rock in the formation expressed as a ratio (e.g. 90% = 0.9) ρ matrix = density of rock matrix (g / cm 3 ) It is.

[0058] Equation 2 expresses the density log response (ρ log ) is the porosity ratio (Φ) and the fluid density (ρ fluid ) multiplied by the remaining volume fraction (1-Φ) and the rock matrix density (ρ matrix Equation 2 shows that it is equal to the sum of the multiplications of ρ fluid Any of the variables in Equations 1-3 may be present in geophysical well logs or other logging logs, and may be obtained by the image or data analysis component of a computer program used to determine the information. fluid ) can then be used to identify fluids within the pore spaces in the rock matrix.

[0059] Equations 1 and 2 describe a scenario in which a single fluid occupies the pore space in the rock matrix of a rock formation. As a result, the values ​​presented are end-members, but natural systems may show intermediate values ​​consistent with mixtures of multiple fluids. In the case of a mixture of multiple fluids, the relative porosity ratios of the fluids should be multiplied by the relative fluid densities or corresponding interval transit times and summed.

[0060] Multiple pore fluids combine to affect acoustic slowness and density measurements (e.g., fluid density is equal to the proportional sum of the densities from each component, and acoustic slowness is calculated from the proportional sum of the acoustic slowness from each component). For example, using Equations 1 and 2, a mixture of 50% water and 50% hydrogen in a sandstone matrix with 20% porosity has a ρ log is 2.22g / cm 3 (For example, the sum of the contributions of rock, water, and hydrogen is 0.8 × 2.65 g / cm 3 +0.1×1.0g / cm 3 +0.1×1.79×10 -4 g / cm 3 ) and Δt log is 88.4 μs / ft (e.g., 0.8 × 55.5 μs / ft + 0.1 × 200 μs / ft + 0.1 × 240 μs / ft from the combined contributions of rock, water, and hydrogen). Using the same approach, a mixture of 25% water and 75% hydrogen has a ρ log is 2.17g / cm 3 , Δt log 90.4 μs / ft. By comparison, a mixture of 50% water and 50% methane in the same matrix has a ρ log is 2.22g / cm 3 , Δt logis 132.7 μs / ft. Because density and acoustic slowness may not be unique (i.e., multiple fluid combinations may yield the same value), the likelihood and range of fluid compositions can be predicted by simulation (e.g., Monte Carlo techniques). However, such techniques may utilize information gathered from additional well logs (e.g., resistivity logs) and laboratory experiments (e.g., flooding experiments to determine the effect of fluid composition on acoustic slowness in rock samples) to improve the accuracy of the calculations based thereon.

[0061] Based at least in part on the determined fluid types and their relative amounts, the amount of the one or more selected fluids in the rock formation can be quantified. For example, the relative amount of the one or more fluids in the rock formation (e.g., the percentage of the pore space filled with the fluid) can be multiplied by the size of the rock formation (determined from multiple wells confirming the size of the rock formation in a well field) and the volume of the pore space therein to calculate an estimated volume of the one or more selected fluids in the entire subterranean section or rock formation.

[0062] The presence of hydrogen within rock pores may register different signals based on the confining lithology. Data from well logs can be analyzed utilizing computational programs that calculate acoustic and density responses and identify corresponding subsurface intervals that exhibit specified response values ​​(e.g., response values ​​indicative of the target fluid of interest). For example, if hydrogen gas is present in a sedimentary layer, the signature may be more similar to traditional oil and gas observations, such as gas crossover, although at a lower slowness than oil or methane.

[0063] As described above, the porosity of the rock formation (e.g., porosity from well logs or measured porosity) can be used to accurately determine one or more of the fluid density or acoustic slowness of one or more fluids in the pore space in blocks 150 and 160.

[0064] The step of determining the fluid density of the fluid in the pore space of the rock formation at block 150 includes calculating the fluid density of one or more fluids in the pore space using Equation 2. For example, Equation 2 can be expressed as ρ fluid The values ​​of one or more of the variables in Equation 2 may be obtained from a well log and input into the rearranged Equation 2. A computer program may be utilized to automatically identify values ​​of one or more of the variables in Equation 2 in the geophysical well log and, based thereon, determine the fluid density (ρ fluid ) can be calculated. Thus, the challenging data acquisition, determination, and associated calculations can be performed automatically and quickly to determine the fluid density. One or more of the variables can be obtained from different well logs, for example, downhole gamma ray logging logs, photoelectric coefficient geophysical logging logs, acoustic logging logs, or any of the logging logs disclosed herein. For example, the computer program can calculate the fluid density ρ, which is the last remaining variable in the density equation (Eq. 2). fluid Bulk density well log measurements can be identified and used to solve for

[0065] Fluid density (ρ fluid ) is 1.00g / cm 3 Much smaller than, for example, 0.8 g / cm 3 If it is smaller, the fluid is likely to be in the gas phase, leading to selection of methane, hydrogen, helium, nitrogen, mixed hydrocarbon gases, dihydrogen sulfide, carbon dioxide, or mixtures thereof.

[0066] Determining the fluid density of a fluid in the pore space of a rock formation may include determining the fluid density of one or more fluids in one or more subsurface intervals within the pore space in the geological region of interest. Thus, method 100 may determine fluid density for some or all of the subsurface intervals in a formation or wellbore therein.

[0067] Figures 2A and 2B graph the expected density log responses for different end-member gases across a range of porosities for assumed sandstone (left) and gabbro (right) matrices, respectively. More specifically, Figures 2A and 2B graph the output of density log logs calculated according to the inputs in Equation 3 and Tables 1-3. The output was calculated for various density log responses using Equation 3 for hypothetical sections with porosities ranging from 5% to 25% and filled with various percentages of water, hydrogen, helium, methane, nitrogen, gaseous carbon dioxide, and supercritical carbon dioxide. As shown in Figures 2A and 2B, based on the similar densities between each of the selected gases, hydrogen, helium, methane, and nitrogen are nearly indistinguishable from one another, while all of these gases are readily distinguishable from water or carbon dioxide in either the gaseous or supercritical states.

[0068] The inputs to Equation 1 (the acoustic equation) are known once the rock type and porosity have been determined, such as from well logs, as described herein.

[0069] The step of determining the acoustic slowness (e.g., fluid slowness or interval transit time) of the fluid in the pore space at block 160 includes calculating the acoustic slowness of one or more fluids in the pore space using Equation 1. For example, Equation 1 can be rearranged to obtain Δt fluid can be solved. One or more values ​​of the variables in Equation 1 can be obtained from a well log and input into the rearranged Equation 1. A computer program can be utilized to automatically identify values ​​for one or more of the variables in Equation 1 in a geophysical well log and calculate the fluid slowness of one or more fluids in a corresponding underground section based thereon. One or more of the variables can be obtained from different well log logs, such as a downhole gamma ray log, a photoelectric coefficient geophysical log, an acoustic log, or any of the log logs disclosed herein. For example, the section transit time of an acoustic log (e.g., the bulk transit time through one or more fluids in the pore space) can be obtained from an acoustic log and the last remaining variable of Equation 1 can be calculated.

[0070] Determining the acoustic slowness of the fluid in the pore space may include determining the acoustic slowness in one or more subsurface intervals within the pore space in the geological region of interest. Thus, method 100 may determine the acoustic slowness for some or all of the subsurface intervals in the formation or wells therein.

[0071] Figures 3A and 3B plot the acoustic logging response (e.g., acoustic slowness) to different end-member gases over a range of porosities for assumed sandstone and gabbro matrices, respectively. More specifically, Figures 3A and 3B plot the output calculated according to the inputs in Equation 1 and Tables 1-3. The acoustic response output is calculated over a porosity range of 5% to 25% filled with various percentages of water, hydrogen, helium, methane, nitrogen, and carbon dioxide. In this way, hydrogen and helium can be easily distinguished from methane, nitrogen, and carbon dioxide in their gaseous or supercritical states.

[0072] The determined fluid densities and acoustic slownesses corresponding to one or more subsurface intervals can be used to determine or identify one or more fluid types within the pore space in one or more subsurface intervals in a geological region of interest.

[0073] Determining the fluid type in the pore space in block 170 may include determining one or more fluid types in the pore space in one or more subsurface sections. Determining the fluid type in the pore space in block 170 may include determining the one or more fluid types based on the determined fluid densities and acoustic slownesses of the one or more fluids. Determining the fluid type in the pore space in block 170 may include comparing bulk fluid density values ​​and acoustic slowness values ​​for corresponding rock matrices (e.g., one or more rock matrix types and one or more porosities) to known bulk fluid density values ​​and acoustic slowness values ​​corresponding to known fluids and corresponding amounts thereof. In such an example, the one or more fluid types are easily identified and their relative amounts are also identified.

[0074] The calculated fluid density and acoustic slowness within a subsurface section may be used to identify one or more fluid types therein. Determining the fluid type within the pore space of the rock formation may include correlating the fluid density and acoustic slowness of the fluid within the pore space of the rock formation to known combinations of fluid density and acoustic slowness of one or more of hydrogen, methane, hydrogen, helium, water, or carbon dioxide. For example, if the calculated acoustic slowness value is less than 250 μs / ft, the calculated fluid density may be less than 1.00 g / cm. 3 (For example, 0.9 to 1.2 g / cm 3 ) the fluid is identified as water and the fluid density is close to 1.00 g / cm 3 If the calculated acoustic slowness is within the range of 500-750 μs / ft and the density is 1.00 g / cm, it is identified as hydrogen. 3 If the calculated acoustic slowness is in the range of 750-1,000 μs / ft and the density is less than 1.00 g / cm, the fluid is identified as methane. 3 much smaller than, for example, 0.8 g / cm 3 If the calculated acoustic slowness is greater than 1,000 μs / ft, the fluid is identified as carbon dioxide.

[0075] A fluid can be distinguished from one or more other fluids by examining both the determined fluid density and acoustic slowness of one or more fluids in the pore space compared to the fluid densities and acoustic slowness of other known fluids found in similar rock matrix types. For example, the relatively large amounts of hydrogen, methane, and carbon dioxide in a rock formation (e.g., at least 20% by volume of the rock formation) have a density of 2.2 g / cm 3 By identifying a bulk density less than 100 μs / ft, the fluids can be distinguished from water and relatively small amounts (e.g., 10% or less by volume of the rock formation) of hydrogen, methane, and carbon dioxide. Similarly, the relatively large amounts of hydrogen, methane, and carbon dioxide in a sandstone rock formation can be distinguished from one another by comparing the acoustic slowness of the respective fluids. For example, a sandstone with a porosity of 20% can be filled with hydrogen with an acoustic slowness value of about 90 μs / ft, filled with methane with an acoustic slowness value of about 180 μs / ft, and filled with carbon dioxide with an acoustic slowness value of about 260 μs / ft. Comparing the determined bulk density in the rock formation to known bulk densities can help distinguish fluids such as hydrogen, helium, methane, and carbon dioxide from hydrocarbons, water, and other fluid mixtures in the rock formation, and comparing the determined acoustic slowness of fluids in the rock formation can help further distinguish the fluids from one another, for example, to distinguish hydrogen, methane, and carbon dioxide from one another and from other fluids.

[0076] Figure 4 is a synthetic log showing bulk density and acoustic slowness response over a range of porosities and fluid compositions according to one embodiment. Specifically, Figure 4 shows hypothetical synthetic geophysical log data showing different log responses for a hypothetical continuous 25-foot thick sandstone section with 0% porosity, 10% water-filled porosity, 10% hydrogen-filled porosity, 15% mixed fluid (18% methane, 1% carbon dioxide, 26.5% hydrogen, 49.5% water, 4.5% helium, and 0.5% nitrogen)-filled porosity, 10% carbon dioxide-filled porosity, 20% water-filled porosity, 20% hydrogen-filled porosity, 20% methane-filled porosity, and 20% carbon dioxide-filled porosity. Pore ​​space filled with hydrogen, helium, or carbon dioxide can be distinguished from water, methane, or other gases by combining density logs with geophysical and acoustic logs.

[0077] Hydrogen- or helium-filled pores are distinguished from water- or methane-filled rocks of the same porosity by the relatively low fluid densities of hydrogen and helium combined with intermediate transit times for hydrogen and helium. A water-filled sandstone with a porosity of 20% has a density of 2.32 g / cm 3 , the section transit time was 84 μs / ft, and the density of hydrogen-filled pores was 2.12 g / cm 3 , resulting in a section transit time of 92 μs / ft. The methane-filled and helium-filled pores have approximately the same density as the hydrogen-filled pores in this scenario, approximately 2.12 g / cm. 3 However, they can be distinguished by the interval transit time of 181 μs / ft for methane and 107 μs / ft for helium. The density of the pores filled with carbon dioxide is 2.15 g / cm 3Although not as low as methane- or hydrogen-filled pores, the interval transit time is much higher at 262 μs / ft. Instead, if hydrogen is contained in basalt with a porosity of 8%, the corresponding density and slowness values ​​for basalt in Tables 1 and 2 indicate that the hydrogen-filled pores have a density of 2.44 g / cm. 3 and a section transit time of 67 μs / ft are predicted. In contrast, the density of the same pores filled with water is 2.52 g / cm 3 and the interval transit time is 63 μs / ft. Thus, the relatively low fluid density and relatively high acoustic slowness values ​​(compared to other samples in the subsurface interval) indicate the presence of hydrogen or helium in the pore space of the rock formation.

[0078] Based on the techniques disclosed above, fluids such as hydrogen, helium, carbon dioxide, methane, etc., can be differentiated from other subsurface fluids using geophysical density logs, geophysical acoustic logs, mud logs, etc., to determine the fluid density and corresponding acoustic slowness of the fluid in the pore space of the rock formation as described above. For example, hydrogen can be differentiated from one or more of nitrogen, carbon dioxide, water, or hydrocarbon fluids by comparing the determined fluid density and acoustic slowness of hydrogen with the fluid density and acoustic slowness of nitrogen, carbon dioxide, water, or hydrocarbons (e.g., methane, crude oil, etc.). The difference between them indicates a difference in fluid type. Carbon dioxide can be differentiated from one or more of nitrogen, hydrogen, water, or hydrocarbon fluids by comparing the determined fluid density and acoustic slowness of carbon dioxide with the fluid density and acoustic slowness of nitrogen, hydrogen, water, or hydrocarbons. Helium can be distinguished from one or more of nitrogen, carbon dioxide, hydrogen, water, or hydrocarbon fluids by comparing the determined fluid density and acoustic slowness of helium to the fluid density and acoustic slowness of nitrogen, carbon dioxide, hydrogen, water, or hydrocarbons. Methane can be distinguished from one or more of nitrogen, carbon dioxide, hydrogen, water, or other hydrocarbon fluids by comparing the determined fluid density and acoustic slowness of methane to the fluid density and acoustic slowness of nitrogen, hydrogen, water, or hydrocarbons (e.g., methane, crude oil, etc.).

[0079] A multi-stage comparison of the fluid density and acoustic slowness of the fluid in the wellbore with known fluid densities and acoustic slowness of various fluids can be used for the determination of fluid type by differentiation. For example, at one or more points during differentiation, the identity of the fluid in the pore space may be unknown, but may be determined by a direct comparison of the determined fluid density and acoustic slowness of the fluid in the pore space with known values ​​for various fluids in similar or identical rock formations. A correspondence between these indicates a possible match between the determined fluid properties and the selected fluid type. A lack of correspondence between the determined fluid properties and the acoustic slowness and fluid density of known fluids can help to rule out some fluid types as unknown fluid types.

[0080] The step of flagging the selected fluid type determination in block 180 includes outputting an indication of one or more fluids in the pore space. For example, the step of flagging the selected fluid type in block 180 includes flagging one or more selected types of fluids, such as hydrogen, helium, carbon dioxide, methane, etc., from the determined fluid types. The computer program may flag the identified hydrogen, methane, carbon dioxide, etc., on each well log data set as output. The flags may include an electronic output of the fluid types at corresponding depths and locations in the geological region of interest. Such flags may be output in text form or as a list of one or more fluids and corresponding depths in the geological region of interest, such as on the well log. The flags may indicate the amount of the identified one or more fluids in one or more subsurface intervals in the geological region of interest.

[0081] The method 100 can include outputting the flags, such as listing the determined fluids and corresponding subsurface intervals in one or more geological regions of interest, such as a well or field of wells. The flags can be output as a list, map, or other digital display. The flags can also be output as data on a well log along with the corresponding data.

[0082] The method 100 may include obtaining data logs, such as accessing digitally or electronically stored well geophysical logs. The method 100 may include obtaining data for well geophysical properties from the well log logs, such as accessing and reading one or more of rock matrix type, bulk acoustic slowness, porosity, etc., from one or more well log logs (e.g., well geophysical logs). The digital well log data provides information about one or more variables useful in Equations 1-3 for one or more subsurface intervals in a geological region of interest. The method 100 may include digitizing paper well log logs and performing image analysis on the digitized paper well log logs to obtain the digital well log data.

[0083] In some examples, if the porosity and rock matrix type or rock formation are known, method 100 may begin with block 150. In some examples, if the fluid density or acoustic slowness is known for one or more subsurface intervals, block 150 or block 160 may be omitted from method 100.

[0084] The ability to differentiate fluid types in porous subsurface formations allows for the identification and exploration of selected fluids (e.g., hydrogen, helium, or carbon dioxide) in the subsurface. The techniques described herein can be used in combination with thousands of well geophysical logs available through public and proprietary databases in the United States and further worldwide to identify subsurface hydrogen, helium, or carbon dioxide resources and / or identify subsurface hydrogen or carbon dioxide reservoirs or adjacent formations. These well geophysical log or other wireline log data can also be used to quantify and confirm subsurface hydrogen, helium, or carbon dioxide storage, or carbon sequestration through subsurface carbon mineralization. Longitudinal (time-course or time-series) collection of these well geophysical log or other wireline log data may be used to further quantify and verify subsurface hydrogen, helium, or carbon dioxide storage, or carbon sequestration through subsurface carbon mineralization. For example, data from longitudinal collections of well logs can be compared to determine the relative differences between carbon dioxide and hydrogen or helium content over time, such as to determine fluid sequestration or depletion in the formation. Such techniques can be used to monitor the injection of one or more fluids into an earth formation.

[0085] Method 600 may include drilling one or more wells based on the determined indication of the presence, absence, or amount of the selected one or more subsurface fluids generated from method 600. Examples of drilling are described in more detail below. Such drilling may be for the purpose of injecting fluids or gases into the rock formation or for the purpose of withdrawing the selected one or more fluids from the rock formation. For example, drilling may be performed in method 600 to withdraw hydrogen based on a determination of the presence of a subsurface hydrogen reservoir in one or more subsurface intervals. Method 600 may include injecting one or more fluids into a subsurface interval of interest (e.g., for sequestration, storage, or fracturing) or withdrawing one or more fluids from a subsurface interval of interest.

[0086] As described in more detail below, during exploration for hydrogen, helium, carbon dioxide, or other gases, computer-aided algorithms can be used to search geophysical well log data and solve for fluid type using the techniques and equations disclosed herein. Computer-aided algorithms can be used to identify subsurface rock formations that contain hydrogen, helium, carbon dioxide, or other gases subsurface. Any portion of method 100, such as blocks 110-180, may be performed by a computing device (e.g., a computer) as an algorithm stored therein. For example, the calculations of fluid density and fluid slowness in blocks 150 and 160 can be performed on a computer for depths on the well log for the geological region of interest.

[0087] FIG. 5 is a block diagram of a system 500 for implementing the methods disclosed herein, according to an embodiment. The system 500 is a targeting system for targeting (e.g., identifying and quantifying) selected fluids in a rock formation, such as hydrogen, helium, carbon dioxide, methane, etc. The system 500 includes a computing device 510 having at least one processor 511 and a memory storage device 512 having data and one or more operating programs stored thereon. The memory storage device 512 (e.g., a non-transitory memory storage medium) is in electronic communication with the processor 511. The system 500 includes a communication network 520 in electronic communication with the computing device 510. The system 500 can include an image log 530 and numerical log data 540 obtained from a paper well log log 550, a digitized well log log 560, or digitization of a well log device 570 at a drilling site. The image log 530 and numerical log data 540 can be obtained via the communication network 520.

[0088] At least one computing device 510 may include one or more servers, one or more computers (e.g., desktop computers, laptop computers), or one or more mobile computing devices (e.g., smartphones, tablets, etc.). The processor 511 of the computing device 510 includes hardware for executing instructions such as those constituting an operating program (e.g., instructions for performing any one or more portions of the methods disclosed herein). The processor 511 is configured to read and execute operating programs stored in the memory storage device 512.

[0089] The memory storage device 512 of the computing device may include one or more of volatile and non-volatile memory, such as random access memory (RAM), read only memory (ROM), solid state disk (SSD), flash, phase change memory (PCM), or other types of data storage. The memory storage device 512 may be internal or distributed memory. One or more operating programs stored in the memory storage device 512 may include machine-readable and executable instructions for performing any portion of the methods disclosed herein. For example, the one or more operating programs may include an image analysis engine 513, a numerical digital analysis engine 514, a relevance determination engine 515, etc. The memory storage device 512 also has a data store 516 therein for storing one or more data sets, outputs of the methods disclosed herein, or any other digital information used in the methods disclosed herein.

[0090] For example, the data store 516 may include imported well log logs (eg, electronic data logs or image logs) having numerical or other data used by the analysis and decision engines.

[0091] The image analysis engine 513, the numerical digital analysis engine 514, and the relevance determination engine 515 may be stored in the memory storage device 512 as operating programs having instructions for performing the calculations and analysis techniques disclosed herein. The memory storage device may include a data store of imported well log logs (e.g., electronic data logs or image logs) having numerical or other data used by the analysis engine and the determination engine.

[0092] Computing device 510 may include input / output ("I / O") devices / interfaces (not shown). One or more I / O devices / interfaces are configured and provided to enable a user to provide input to computing device 510, receive output from computing device 510, and otherwise transfer data to and from computing device 510. These I / O devices / interfaces may include a mouse, a keypad or keyboard, a touch screen, a camera, an optical scanner, a network interface, web-based access, a modem, a port, other known I / O devices, or a combination of these I / O devices / interfaces. A touch screen may be operated with a stylus or a finger.

[0093] The I / O device / interface may include one or more devices for presenting output to a user, including, but not limited to, a graphics engine, a display (e.g., a display screen or monitor), one or more output drivers (e.g., a display driver), one or more audio speakers, and one or more audio drivers. For example, the I / O device / interface may be configured to provide graphical data to a display for presentation to a user. The graphical data may be representative of one or more graphical user interfaces and / or other graphical content that may be useful in a particular implementation.

[0094] The computing device 510 may further include a communications interface (not shown). The communications interface may include hardware, software, or both. The communications interface may provide one or more interfaces for communication (e.g., packet-based communications, etc.) between the computing device 510 and one or more additional computing devices or one or more networks. For example, the communications interface may include a network interface controller (NIC) or network adapter for communicating with an Ethernet or other wired-based network, or a wireless NIC (WNIC) or wireless adapter for communicating with a wireless network, such as a WI-FI network.

[0095] Any suitable network and any suitable communication interface may be used. For example, the computing device 510 may communicate with one or more portions of an ad-hoc network, a personal area network (PAN), a local area network (LAN), a wide area network (WAN), a metropolitan area network (MAN), or the Internet, or a combination of two or more thereof. One or more portions of these one or more networks may be wired or wireless. As an example, one or more portions of the computing device 510 may communicate with a wireless PAN (WPAN) (e.g., a BLUETOOTH WPAN, etc.), a WI-FI network, a WI-MAX network, a cellular telephone network (e.g., a Global System for Mobile Communications (GSM) network, etc.), or other suitable wireless network, or a combination thereof. The computing device 510 may include any suitable communication interface to any of these networks as desired.

[0096] Computing device 510 may include a bus (not shown). The bus may include hardware, software, or both that couples components of computing device 510 together. For example, the bus may include an Accelerated Graphics Port (AGP) or other graphics bus, an Extended Industry Standard Architecture (EISA) bus, a Front Side Bus (FSB), a HYPERTRANSPORT (HT) interconnect, an Industry Standard Architecture (ISA) bus, an INFINIBAND interconnect, a Low Pin Count (LPC) bus, a MicroChannel Architecture (MCA) bus, a Peripheral Component Interconnect (PCI) bus, a PCI Express (PCIe) bus, a Serial Advanced Technology Attachment (SATA) bus, a Video Electronics Standard (VLB) bus, or any other suitable bus, or any combination thereof.

[0097] The communications network 520 may include an information system that enables electronic transfer of data between remote sources, such as the World Wide Web, a local wireless network, a local area network, etc. The communications network 520 may also include one or more cloud-based components. The computing device 510 is in electronic communication with the remote image log 530 and the numerical log data 540, such as via the communications network 520 (e.g., an Internet connection, an Ethernet connection, or a local area network).

[0098] The numerical log data 540 may be provided by digitizing existing paper logs 550, acquiring existing digitized logs 560, or from an on-site well logging system 570 (e.g., a logging truck at a drilling site). The numerical (well) log data 540 and the image log data 530 may be accessed and used by the computing device 510 to perform any portion of the methods disclosed herein. For example, the numerical log data 540 and the image log data 530 may be downloaded and stored in the data store 516 for use by one or more of the image analysis engine 513, the numerical digital analysis engine 514, or the relevance determination engine 515 to identify and quantify selected fluid types within rock formations in the geological region of interest.

[0099] The image analysis engine 513 can analyze images of the well log to identify and record information therein. For example, the image analysis engine 513 can examine digitized images of paper well log logs to identify properties of rock formations and one or more fluids therein, such as resistivity, neutron porosity, rock type, bulk density, etc., and record them in electronic form.

[0100] FIG. 6 is a block diagram of an image analysis method 600 according to an embodiment. The image analysis method 600 can be implemented on the computing device 510 disclosed above. The image analysis method 600 includes receiving information about an imaged or digitized well log at block 610, estimating a likelihood that a property of the well log indicates an accumulation of a selected fluid (e.g., hydrogen, helium, or carbon dioxide) at block 620, and determining whether the estimated likelihood meets a predetermined threshold for the likelihood of the presence of the accumulation of the selected fluid at block 630. In response to determining whether the estimated likelihood meets the predetermined threshold, the image analysis method 600 includes outputting an indication of whether a property of the well log indicates the presence of an accumulation of the selected fluid at blocks 650 and 640, respectively. The image analysis method 600 includes outputting a probability or confidence that the property indicates the presence of the selected fluid at block 625.

[0101] The step of receiving information about the imaged or digitized well log at block 610 may include receiving information (e.g., well log data or images) on a computing device. The information may include images or data from well log logs or digitized well log logs that indicate rock matrix properties in one or more subsurface intervals in one or more geological regions of interest. The imaged or digitized well log may include any of the well log logs disclosed herein, such as multiple well log logs each providing a different property.

[0102] The step of estimating the likelihood that the well log characteristics indicate an accumulation of the selected fluid at block 620 may include performing one or more portions of method 100 (FIG. 1). The estimated likelihood that the well log characteristics indicate an accumulation of the selected fluid may include a binary indication of yes or no indicating that an accumulation of the selected fluid is present. In some examples, the estimated likelihood that the well log characteristics indicate an accumulation of the selected fluid may include an indication of a selected number of fluids in a single geological region of interest, an indication of the presence of the selected one or more fluids in a selected number of subsurface intervals, a selected amount of the selected one or more fluids, or a combination of the foregoing, determined using any of the methods disclosed herein.

[0103] In some examples, the estimated likelihood may be expressed as a probability or confidence interval that the characteristic indicates the presence of a selected fluid. The probability or confidence interval may be based on a statistically acceptable deviation of the calculated amount of one or more fluids from a target value (e.g., within 10% of the target value, or at least within 90% of the target value). Thus, the probability or confidence interval may be expressed as a percentage or ratio to the target value.

[0104] The step of outputting the probability or confidence that the property indicates the presence of the selected fluid at block 625 may include outputting an indication of the presence of the selected fluid or fluids in one or more subsurface sections in one or more geological regions of interest in one or more well log logs, maps, or lists in digital format. The selected fluids of interest may include hydrogen, helium, methane, carbon dioxide, or any other fluid or fluids. For example, the image analysis method 600 may include outputting the probability or confidence that the property indicates the presence of hydrogen, helium, or carbon dioxide. This output may be transmitted to a memory storage device of a computing device for compilation into a report or for correlation with the image or a location corresponding to the image. This output may also be transmitted to a remote computing device.

[0105] The step of determining whether the estimated likelihood meets predefined thresholds for the likelihood of the presence of an accumulation of the selected fluids at block 630 may include comparing whether the determined indications within a single geological region of interest, the determined indications of the presence of the selected one or more fluids in a selected number of subsurface intervals, the determined quantities of the selected one or more fluids, or a combination of the foregoing, meet or exceed the thresholds. These thresholds may be input to the image analysis engine 513. These thresholds may be based on values ​​indicative of a profitable reservoir for the selected fluids based on one or more considerations, such as depth, drilling costs, pumping costs, etc.

[0106] In response to determining whether the estimated likelihood meets a predetermined threshold, the method 600 includes outputting an indication that the well log characteristics do not indicate the presence of the selected fluid accumulation 640 or that the well log characteristics indicate the presence of the selected fluid accumulation 640. This output may be transmitted to a memory storage device of the computing device for compilation into a report or for correlation with the image or a location corresponding to the image. This output may be transmitted to a remote computing device.

[0107] In some examples, the image analysis method may be more simplified and may include receiving well log images, analyzing the well log images to determine the presence of log characteristics consistent with a selected subsurface fluid, and outputting the analysis results as raw data. Such analysis may include any portion of method 100 and method 600, and the output may include outputting a report of the analysis results. This output may be in the form of a map, a well log, or a report listing the analysis results, such as providing information regarding the location, depth, and quantity of the selected fluid in the geological region of interest.

[0108] The image analysis methods disclosed herein may be implemented in whole or in part in an image analysis engine 513 stored in a computing device 510 .

[0109] In some examples, the image analysis engine may be implemented as an artificial intelligence program. The artificial intelligence program may be trained to classify images of geophysical well logs, according to one embodiment. The training algorithm includes a first step of receiving a training dataset of labeled images exhibiting well log-based features consistent with accumulation of one or more selected subsurface fluids (e.g., hydrogen, helium, carbon dioxide, methane, mixed hydrocarbons, or mixtures thereof), a second step of training an image classification module using the training dataset, and a third step of hosting the image classification model by the image analysis engine.

[0110] The model may be constructed by a model generator, such as in accordance with the image training dataset and Equations 1-2 (e.g., ensuring that a model constructed based on the training images complies with method 100 and Equations 1-2, as applicable). Training the image classification module using the training dataset may include ensuring that the image classification module utilizes one or more portions of method 100 or method 600. For example, the image classification module may operate in accordance with Equations 1-2 used in method 100.

[0111] 5, the numerical digital analysis engine 514 may include machine readable and executable instructions to operate similarly or identically to one or more portions of the method 100 using data obtained from the numerical log data 540. The output of the numerical analysis engine 514 may be similar or identical in one or more aspects to the output of the image analysis engine 513.

[0112] The relevance determination engine 515 may include machine-readable, executable instructions for determining the relevance of determined properties of one or more fluids in one or more subsurface sections in a geological region of interest to selected criteria, such as selected fluid types, amounts of selected fluid types, number and / or location of subsurface sections including selected fluid types and their amounts, etc. Thus, the relevance determination engine 515 may determine whether the one or more fluids in the subsurface formation indicate the presence of a reservoir of the selected one or more fluids large enough to be of interest to an extractor, an amount of depletion or sequestration of the selected one or more fluids in the subsurface formation, etc.

[0113] The output of the relevance determination engine 515 may be similar or identical to the output of the image analysis engine 513 in one or more aspects.

[0114] In some examples, one or more of the image analysis engine 513, the numerical digital analysis engine 514, and the relevance determination engine 515 may be omitted from the system 500.

[0115] Any portion of method 100, method 600, image analysis engine 513, numerical digital analysis engine 514, or relevance determination engine 515 may form a discrete portion of software for identifying and quantifying selected fluid types within rock formations in a geological region of interest.

[0116] The following examples are provided to illustrate various embodiments of the methods, components of the methods, systems, components of the systems, applications and materials disclosed herein, and are intended for illustrative purposes and should not be construed as limiting or otherwise limiting the scope of the claims.

[0117] (Assumed example) 7A and 7B are flow diagrams of analysis of a geological map and corresponding well log logs, according to an embodiment. FIG. 7A and 7B show how the techniques disclosed herein for determining the presence of selected subsurface fluids are utilized for well planning and drilling. A geological map 710 shows the location of igneous rocks 712 (e.g., granite, basalt, or gabbro) in a geological region of interest. Igneous rocks are potential source rocks for hydrogen generation underground. The geological map 710 shows the locations of wells 701, 702, 703, and 704 previously drilled in the area.

[0118] Wells 701 and 702 are potential wells of interest because they are located on mapped igneous rocks, and correspondingly, the well logs for wells 701 and 702 may be evaluated using the techniques disclosed herein.

[0119] In FIG. 7A, well log logs corresponding to well 701 are analyzed using method 100 (FIG. 1). The output of method 100 for three different intervals of well 701 shows sandstone reservoirs at 500-1,000 feet, 1,500-2,000 feet, and 3,000-3,500 feet that are filled with methane, hydrogen, and carbon dioxide, respectively. The hydrogen-filled sandstone reservoir at 1,500-2,000 feet is the drilling target of interest. A drilling plan is then developed to drill a new well at or near the location of well 701 to a target depth of 2,000 feet.

[0120] In FIG. 7B, well logs corresponding to well 702 are analyzed using method 100 (FIG. 1). The output of method 100 for three different intervals of well 702 shows sandstone reservoirs at 500-1,000 ft, 1,500-2,000 ft, and 3,000-3,500 ft, filled with methane, water, and carbon dioxide, respectively. At this location, no steps are taken to drill towards hydrogen reservoirs.

[0121] (Example) FIG. 8 is a display of wireline well log data showing gamma ray measurements (API) and caliper measurements from a well. The information in FIG. 8 indicates rock type based on the gamma ray and caliper measurements. Measurements in the hatched areas indicate that the rock type in the corresponding underground interval is sandstone. The sandstone rock type was used to determine fluid density and acoustic slowness as specified in method 100.

[0122] FIG. 9 is a representation of wireline well log data showing resistivity measurements from the well of FIG. 8. The resistivity measurements of FIG. 12 were used to determine the porosity of the rock formations in the well and the fluid type therein. Measurements in the hatched areas indicate the presence of hydrogen in the corresponding subsurface interval. For example, the resistivity was used to calculate fluid density and acoustic slowness of one or more fluids, as described in method 100.

[0123] FIG. 10 is a representation of wireline well log data showing slowness, bulk density, and neutron porosity measurements from the well of FIG. 8. The slowness measurements (μs / ft), bulk density measurements (g / cm 3 ), and neutron porosity measurements (%) were used to determine the fluid density and acoustic slowness of the fluid therein. Measurements in the hatched areas indicate the presence of hydrogen in the corresponding subsurface interval. For example, the acoustic slowness (Δt fluid ) to determine the slowness (e.g., bulk slowness or Δt log ) was used. Bulk density (ρ log ) and porosity (Φ) are determined by the fluid density (ρ fluid ) was used to determine

[0124] Figure 11 is a mud gas mass spectrometry log from a recently drilled well targeting the hydrogen-rich reservoir in the well of Figure 8. The highlighted interval located within the sandstone has density, porosity, and sonic log values ​​indicative of a mixture of water and hydrogen in the pore space based on the information in Figures 8-10. Notably, Figure 11 shows a consistent increase in hydrogen in the mud gas stream over background in the same interval. Thus, the presence of hydrogen in the drilling mud confirms the determination of a hydrogen reservoir at the corresponding depth in the well.

[0125] FIG. 11 is an example verifying that the methods, systems, and software disclosed herein can successfully identify a selected fluid, such as hydrogen, within a subterranean formation.

[0126] The methods, systems, and software disclosed herein may be used in any number of industries and applications. For example, the methods, systems, and software disclosed herein may be used to identify underground gas reservoirs, quantify the amount of gas therein, confirm gas sequestration in underground reservoirs, or confirm gas depletion in underground reservoirs.

[0127] Although the focus herein is on hydrogen, helium and carbon dioxide, the techniques disclosed herein are not limited thereto and find application in the identification and quantitative assessment of other subsurface materials including other gases, deposits, minerals and gemstones, as well as materials found in large structures such as foundations, dams, hydroelectric facilities and nuclear facilities.

[0128] In producing natural resources from rock formations in the earth, wells or boreholes are drilled into the earth to where the natural resources are believed to be located. Similarly, in underground storage of gas and greenhouse gas sequestration in geological formations within the earth, wells or boreholes are drilled into the earth to where the greenhouse gases are injected, stored, placed or sequestered. These natural resources can be hydrogen, helium, carbon dioxide, methane or other hydrocarbon gases, dihydrogen sulfide reservoirs, hydrogen reservoirs, helium reservoirs, carbon dioxide reservoirs, dihydrogen sulfide rich reservoirs, hydrocarbon rich reservoirs, and natural resources can be fresh water, brackish water, salt water, heat sources of geothermal energy, or other natural resources, deposits, minerals, metals or gemstones found in the earth.

[0129] The formations that contain these resources may be hundreds, thousands, or tens of thousands of feet below the earth's surface and may be located beneath bodies of water, such as the ocean floor, or beneath other natural resources, such as aquifers. In addition to being at various depths within the earth, these formations may cover areas of different sizes, shapes, and volumes.

[0130] Typically, as a general example, in drilling a well, an initial borehole is drilled into the earth, e.g., at the surface on land or in the ocean, and then subsequent smaller diameter boreholes are drilled to extend the overall depth of the borehole. In this way, the overall borehole decreases in diameter as it gets deeper, so that it can be envisioned as a telescoping assembly of holes, with the largest diameter hole at the top of the borehole closest to the earth's surface.

[0131] Thus, by way of example, the beginning stages of the offshore drilling process may be generally described as follows: Once the drilling rig is positioned at the surface of the water in the area to be drilled, a 36 inch hole is drilled into the earth to a depth of approximately 200-300 feet below the seafloor to form an initial borehole. A 30 inch casing is inserted into the initial borehole. This 30 inch casing is sometimes referred to as a conductor. The 30 inch conductor may or may not be cemented in place. Risers are generally not used during this drilling operation, and cuttings from the borehole, e.g., soil and other material removed from the borehole by the drilling operation, are returned to the seafloor. A 26 inch diameter borehole is then drilled into the 30 inch casing, extending the borehole depth to approximately 1,000-1,500 feet. Again, this drilling operation may be performed without the use of a riser. A 20 inch casing is then inserted into the 30 inch conductor and the 26 inch borehole. The 20 inch casing is cemented into place. A wellhead is secured to the 20 inch casing. (An alternative operation involves drilling a smaller borehole, inserting smaller casing into the borehole, and securing the wellhead to the smaller casing.) A BOP (blowout preventer) is then secured to the riser and lowered by the riser to the seabed where the BOP is secured to the wellhead. From this point, all drilling activity in the borehole is conducted through the riser and BOP.

[0132] It should be noted that riserless offshore drilling operations are also contemplated.

[0133] In the onshore drilling process, larger diameter tubing, such as 30 inches to 20 inches, is not typically used, but the process is similar. Thus, there is generally a surface casing, usually about 13-3 / 8 inches in diameter. This may extend from the surface, e.g., the wellhead or BOP, to a depth of tens to hundreds of feet. One of the purposes of the surface casing is to address environmental concerns of protecting groundwater and preventing greenhouse gases, flammable gases, and salt-rich brine from escaping from the surface casing. The surface casing should have a large enough diameter to allow the passage of the drill string, production equipment such as electronic submersible pumps (ESPs), and circulating mud. Beneath the casing, one or more intermediate casings of different diameters may be used. (It should be understood that there are portions of the borehole that are not cased, and these are referred to as open-holes.) These diameters range from about 7 inches to about 9 inches, but larger and smaller sizes may be used and may extend to depths of thousands or tens of thousands of feet. Inside the casing and running through the borehole from the pay zone, or production zone, to the wellhead at the surface is the production tubing. A borehole may have one or more production tubings, each terminating at a different depth.

[0134] Fluid communication between the formation and the wellbore can be significantly increased by the use of hydraulic fracturing techniques. The first use of hydraulic fracturing dates back to the late 1940s and early 1950s. In general, hydraulic fracturing procedures involve forcing fluids from a wellbore into the formation where they enter the formation and fracture, i.e., force the rock layers apart or fracture. These fractures can range in size from a few microns to a few millimeters, or several millimeters in cross-sectional area, and potentially much larger, forming channels or flow paths. The fractures can also extend in all directions for several feet, a few more feet, tens of feet, or more from the wellbore. The fractures can be kept open by the use of proppants (e.g., sand grains of various sizes) that are pumped into the wellbore with the fracturing fluid in a single operation. It should be remembered that the longitudinal axis of the wellbore in the reservoir may not be vertical. This longitudinal axis may be inclined (upward or downward) or horizontal. Sections of the wellbore that are located within the reservoir, i.e., sections of the formation that contain the natural resource, may be referred to as pay zones. In other embodiments of gas storage, these reservoir sections into which gas is injected may be referred to as storage reservoirs.

[0135] Unless otherwise noted, the terms "hydrogen exploration and production", "carbon dioxide exploration and production", "helium exploration and production", "dihydrogen sulfide exploration and production", "exploration and production activities", "E&P", and "E&P activities" and similar terms as used herein shall be interpreted in the broadest possible manner to include exploration, geological analysis, well planning, reservoir planning, reservoir management, drilling of wells, workover and completion activities, production of hydrogen or helium, flow of hydrogen or helium from wells, recovery of hydrogen or helium, secondary and tertiary recovery from wells, management of flow of hydrogen or helium from wells, underground injection or storage of hydrogen, helium, or carbon dioxide using wells or boreholes, and other upstream activities.

[0136] Unless otherwise specified, the term "earth" as used herein should be interpreted in the broadest possible sense to include the ground, all natural materials, such as rocks, that are or may be found on the ground, and man-made materials, such as concrete.

[0137] Unless otherwise indicated, the terms "offshore" and "offshore drilling activity" and similar terms as used herein are intended to be used in the broadest sense possible to include drilling activities on or in any body of water, whether fresh or salt water, man-made or natural, including rivers, lakes, canals, inland seas, oceans, seas such as the North Sea, bays and ditches such as the Gulf of Mexico, etc. Unless otherwise indicated, the term "offshore drilling rig" as used herein is intended to be used in the broadest possible sense possible to include fixed towers, tenders, platforms, barges, jack-ups, floating platforms, drill vessels, dynamically deployed drill vessels, semi-submersibles, and dynamically deployed semi-submersibles, etc. Unless otherwise indicated, the term "seabed" as used herein is intended to be used in the broadest possible sense possible to include any surface of the earth beneath or under any body of water, whether fresh or salt water, man-made or natural.

[0138] Unless otherwise noted, the term "borehole" as used herein should be given the broadest possible meaning and includes any opening formed in the earth that is substantially longer than it is wide, such as wells, wells, wellbore holes, microholes, slimholes, and other terms commonly used or known in the art to define these types of elongated passages. Wells further include exploratory wells, discovery wells, production wells, abandoned wells, redrilled wells, reclaimed wells, recirculation wells, storage wells, and injection wells. Wells include cased wells, uncased wells, and portions of these wells. Uncased wells, or portions of wells, are also referred to as open holes, boreholes, open boreholes, open bores, or open hole sections. Boreholes may further have segments or sections with different orientations, and they may have straight and arcuate sections, and combinations thereof. Thus, unless expressly stated otherwise, the terms "bottom" of a borehole, "bottom surface" of a borehole, and similar terms as used herein refer to the end of the borehole, i.e., the portion of the borehole furthest along the path of the borehole from the borehole opening, the earth's surface, or the beginning of the borehole. The terms "side" and "wall" of a borehole should be interpreted as broadly as possible and include the longitudinal surfaces of a borehole, whether or not a casing or liner is present, and thus these terms may include the sides of an open borehole or the sides of casing located within a borehole. A borehole may be comprised of a single passageway, multiple passageways, connected passageways (e.g., branched, fishbone, bilateral, trilateral, quadrilateral, pitchfork, feather, or comb configurations), and combinations and variations thereof.

[0139] Boreholes are typically formed and advanced using a mechanical drilling device having a rotating drilling tool, e.g., a bit. For example, when forming a borehole in the earth, the drill bit is typically extended into the earth and rotated to form a hole in the earth. To perform a drilling operation, the bit must be forced against the material to be removed with enough force to exceed the shear strength, compressive strength, or a combination thereof, of the material to be removed. The material that is removed from the earth is commonly known as drill cuttings, e.g., waste, and includes rock fragments, dust, rock fibers, and other types of materials and structures that may result from the interaction of the bit with the earth. These cuttings are typically removed from the borehole using a fluid. The fluid may be a liquid, foam, gas, or other material known in the art.

[0140] Unless otherwise specified, the term "drill pipe" as used herein shall be given the broadest possible meaning and shall include any form of pipe used in drilling activities, and may refer to a single section or portion of pipe. As used herein, "stand of drill pipe", "drill pipe stand", "pipe stand", "stand" and similar type terms shall be given the broadest possible meaning and shall include, for example, two, three or four sections of drill pipe joined together by couplings typically having threaded connections. As used herein, "drill string", "string", "string of drill pipe", "string of pipe" and similar type terms shall be given the broadest possible definition and may include one or more stands coupled together for use in a borehole. Thus, a drill string may include numerous stands and hundreds of sections of drill pipe.

[0141] Unless otherwise noted, the terms "formation," "reservoir," "pay zone," and similar terms as used herein shall be interpreted in the broadest possible sense to include all places, areas, and geological features within the Earth that contain, may contain, or are believed to contain hydrogen, carbon dioxide, helium, and / or dihydrogen sulfide.

[0142] Unless otherwise noted, the terms "field," "oil field," "gas field," and similar terms as used herein shall be construed in the broadest possible sense to include any land, ocean, or body of water loosely or directly associated with a geological formation, particularly a resource-bearing formation. Thus, a field may have one or more exploration and production wells associated with it, a field may have one or more governmental or private resource leases associated with it, and one or more fields may be directly associated with a resource-bearing formation.

[0143] Unless otherwise indicated, as used herein, "conventional hydrogen," "conventional carbon dioxide," "conventional helium," "conventional dihydrogen sulfide," "conventional natural gas," "conventional," "conventional production," and similar such terms are given the broadest possible meaning and include hydrogen, carbon dioxide, helium, or dihydrogen sulfide trapped in underground structures. Generally, in such conventional formations, the hydrogen, carbon dioxide, helium, dihydrogen sulfide, or natural gas travel through permeable or semi-permeable formations to reach the area where they are trapped or accumulated. Generally, in conventional formations, non-porous, relatively impermeable layers overlie or surround the area where the hydrogen, carbon dioxide, helium, dihydrogen sulfide, or natural gas accumulates, thus trapping the hydrogen, carbon dioxide, helium, dihydrogen sulfide, or natural gas in the accumulation. Conventional reservoirs have historically been the source of the majority of observed hydrogen, carbon dioxide, helium, and dihydrogen sulfide. Unless otherwise indicated, the terms "unconventional hydrogen," "unconventional carbon dioxide," "unconventional helium," "unconventional dihydrogen sulfide," "unconventional natural gas," "unconventional," "unconventional production," and similar terms as used herein shall be interpreted in the broadest possible sense to include hydrogen, carbon dioxide, helium, dihydrogen sulfide, or natural gas that is retained in impermeable rocks or that has not migrated into a trap or accumulation area.

[0144] Unless otherwise specified, the term "acoustic speed" as used herein is intended to have the broadest possible meaning and generally refers to the speed at which sound waves travel through a medium (in units of distance per time, e.g., feet per second).

[0145] Unless otherwise noted, the terms "slowness" and "acoustic slowness" as used herein are intended to have the broadest possible meaning and generally refer to the speed at which a medium propagates sound waves (in units of time per distance, e.g., seconds / feet).

[0146] Unless otherwise specified, the term "interval transit time" as used herein is intended to have the broadest possible meaning and generally refers to the time required for a sound wave to pass through a particular interval with a slowness corresponding to the lithology of that interval.

[0147] Unless otherwise specified, the term "acoustic impedance" as used herein should be used in the broadest sense possible and is generally defined as the product of the sound velocity and the density of the medium (kg × m -2 ×s -1 or equivalent British Imperial unit).

[0148] Unless otherwise specified, room temperature as used herein is 25° C. Also, standard temperature and pressure are 25° C. and 1 atmosphere.

[0149] In general, the term "about" as used herein, unless otherwise specified, is meant to encompass a variance or range of ±10%, the experimental or instrumental error associated with obtaining the stated value, preferably whichever is greater.

[0150] Unless otherwise stated, the recitation of ranges of values ​​used herein is merely intended to serve as a shorthand method of referring individually to each separate value falling within the range. Unless otherwise stated herein, each separate value within a range is incorporated herein as if it were individually set forth herein.

[0151] The term "CO2e" is used to define the carbon dioxide equivalent of other more potent greenhouse gases (i.e. methane and nitrous oxide) relative to carbon dioxide on a 100-year Global Warming Potential basis based on the IPCC AR5 methodology. The term "carbon intensity" refers to the life cycle CO2e generated per unit mass of a product.

[0152] CO2 is widely recognized as a greenhouse gas (GHG), and the continued accumulation of CO2 and other GHGs in the atmosphere is expected to cause problematic changes to Earth's ecosystems and contribute to a myriad of other problems, such as ocean acidification and sea-level rise. The two largest sources of global carbon emissions are the use of fossil fuels for electricity generation and transportation.

[0153] Given the risks of CO2 emissions, much effort has been put into finding alternatives to existing high-carbon energy sources or ways to decarbonize existing energy sources, but many of these low-carbon alternatives are not economical or cannot be delivered efficiently enough to replace current options.

[0154] In electricity generation, alternatives to reliable, low-cost but high-emission energy sources (gas and coal) are either deliverable and expensive (e.g. nuclear, hydroelectric, green and blue hydrogen) or cheap and intermittent (e.g. solar, wind, and possibly green hydrogen). There is only one existing low-cost deliverable energy source: geothermal. However, geothermal resources are limited, and many of the more economically productive geothermal resources are already developed and nearing the end of their lifespan, with many already in decline. Thus, the prospects for growth of geothermal energy resources are limited without major technological advances.

[0155] Green hydrogen (hydrogen produced from water without the use of fossil fuels) produced by electrolysis powered by solar, wind, hydroelectric or geothermal energy has the potential to be a reliable source of low-carbon energy when combined with storage, but its applicability is limited by high capital costs, intermittent production due to intermittent energy sources or high energy costs when grid-connected, and the high cost and low availability of suitable hydrogen storage resources. Furthermore, electrolysis consumes significantly more energy to produce hydrogen than is stored in the hydrogen, resulting in low round-trip efficiency of the system.

[0156] Blue hydrogen faces similar problems as green hydrogen: it takes a low-cost, high-emission fuel source like coal or natural gas and turns this low-cost, high-emission energy source into a high-cost, low-emission energy source by adding expensive, parasitic carbon capture equipment. Thus, even if large amounts of hydrogen are produced in a later process that prevents greenhouse gas emissions into the atmosphere, newly developed hydrogen resources are not cost-competitive with other forms of energy derived from fossil fuels. Furthermore, the challenge of finding carbon sequestration resources that can be used to permanently store the carbon captured from such processes currently limits the opportunities for deploying such technology.

[0157] Natural hydrogen (or "gold hydrogen") produced from underground through drilling and producing wells could be a plentiful source of low-emission, low-cost, fully deliverable energy.

[0158] These energy sources and their inherent benefits and limitations are also relevant to transportation. When considering fuels for transportation, the primary fuel sources are diesel and gasoline fuels, both of which are derived from crude oil production. Furthermore, while electric vehicles have been gaining market share in recent years, the cost of electric vehicles is still higher than their fossil fuel counterparts and they also have limitations in terms of cost, charging time, and primary resources for batteries and energy storage. Electric long-haul trucking is also challenging given the weight of the batteries, and most long-haul truck manufacturers are exploring affordable and low-carbon options such as hydrogen-fueled trucking.

[0159] If demonstrated, natural hydrogen would be an answer to low-carbon, low-cost, reliable transportation problems for long-haul trucking and other potential forms of transportation. For other types of transportation, natural hydrogen as a compressed or liquefied product, or as a feedstock for synthetic liquid fuels ("efuels"), would be a reliable, low-cost, low-carbon solution. In addition, natural hydrogen could be combined with nitrogen to produce a carbon-free ammonia product, which has been widely discussed as a potential replacement for bunker fuel oil in shipping.

[0160] Direct emissions reductions: Because hydrogen has no direct CO2 emissions from combustion or typical use, reducing CO2 emissions comes down to what it replaces. In many cases, low-carbon hydrogen replaces hydrogen from steam methane reforming (SMR) as a chemical feedstock for ammonia production, petroleum refining, and other chemical manufacturing. In some cases, low-carbon hydrogen may replace natural gas, diesel fuel, gasoline, or jet fuel as a heat source or transportation fuel.

[0161] For ammonia production and refining, natural gas is used to produce hydrogen through a steam methane reforming reaction, which is then used as a chemical feedstock in both the refining and ammonia production processes. Currently, over 95% of hydrogen is produced using natural gas in a steam methane reformer (SMR). The carbon intensity of hydrogen production using SMR without carbon capture is 10.4 tonnes of CO2 emitted per tonne of hydrogen produced. Thus, the direct replacement of natural hydrogen with hydrogen produced by the SMR process would result in a CO2 reduction of 10.4 tonnes of CO2 / tonne of H2.

[0162] For electricity generation by gas turbines, hydrogen must displace an equivalent amount of energy (btu) from natural gas. Hydrogen has an energy density of 290 btu / cf or 51,682 btu / lb. By comparison, the energy density of natural gas is 983 btu / cf or 20,267 btu / lb, while the carbon intensity of natural gas is 52.91 kg CO2 / mmbtu CH4 or 54.87 kg CO2 / mcf CH4 or 3.5 kg CO2 / kg CH4.

[0163] Hydrogen has 2.6 times higher energy density per unit mass than natural gas, so only 40% of the total tonnage of fuel is needed to achieve the same energy output, so burning one tonne of hydrogen to generate electricity reduces natural gas consumption by around 2.6 tonnes and reduces CO2 emissions by 9.1 tonnes.

[0164] When comparing natural hydrogen to hydrogen produced by electrolysis, the carbon reductions are a function of the carbon intensity of the electricity used in the electrolysis process. However, while there may be significant indirect emissions associated with electrolysis, there are no direct emissions. Therefore, natural hydrogen does not offer any direct emission reductions compared to electrolytic hydrogen.

[0165] Indirect emission reductions: An analysis of the life cycle carbon intensity of natural hydrogen using the Oil Production Greenhouse Gas Emissions Estimator (OPGEE) indicates that the life cycle carbon intensity of natural hydrogen ranges from 0.1 to 0.4 tonnes CO2 / tonne H2. Similar studies on hydrogen production by other methods are not available. However, using an average grid intensity of 0.5 tonnes CO2 / MWh and considering that electrolysis requires about 50 MWh / tonne H2 production, the indirect emissions associated with electrolysis would be about 25 tonnes CO2 / tonne H2 production, assuming grid electricity. Of course, electrolyzer operators can purchase renewable energy credits and synthetically reduce the carbon footprint of electricity usage, but market acceptance of this method as a way to eliminate carbon dioxide emissions in real time may not be permanent.

[0166] Abundant natural hydrogen could provide a significant reduction in equivalent carbon emissions.

[0167] The present invention may be embodied in other specific forms without departing from its spirit or essential characteristics. The described embodiments are to be considered in all respects merely illustrative and not restrictive. The scope of the present invention is therefore indicated by the appended claims rather than by the foregoing description. All changes that come within the meaning and range of equivalency of the claims are embraced within their scope.

[0168] (Additional Note) (Appendix 1) 1. A method for identifying subsurface fluids in a geological formation, the method comprising: determining a rock matrix type of a rock formation in a geological region of interest; determining the porosity of the rock formation; determining a fluid density of a fluid within the pore space of the rock formation; determining an acoustic slowness of the fluid in the pore space; determining a fluid type of the fluid in the pore space; The method includes:

[0169] (Appendix 2) 2. The method of claim 1, wherein determining a rock matrix type in a geological region of interest comprises examining one or more well log logs for the rock matrix type based on its physical properties.

[0170] (Appendix 3) 2. The method of claim 1, wherein determining the rock matrix type in the geological region of interest includes examining one or more of gamma ray well logs, geophysical well logs, mud log logs, or drill cuttings or cores from a well into the rock matrix in the geological region of interest.

[0171] (Appendix 4) 2. The method of claim 1, wherein determining the porosity of the rock formation comprises obtaining porosity data from one or more well log logs.

[0172] (Appendix 5) 5. The method of claim 4, wherein the one or more well log logs include at least one of a resistivity log log, a neutron porosity log log, and an imaging log log.

[0173] (Appendix 6) Determining a fluid density of the fluid in the pore space comprises: ρ log = Bulk density (g / cm) measured by density logging tool 3 ), Φ = porosity of the rock formation expressed as a ratio, ρ fluid = fluid density (g / cm) of the fluid contained within the pore space of the rock formation 3 ), 1-Φ=volume fraction of rock in the formation expressed as a ratio, and ρ matrix = density of the rock matrix (g / cm 3 ), Then, ρ log =(Φ)*ρ fluid +(1-Φ)*ρ matrix Using the density equation of fluid calculating the fluid density of the fluid in the pore space by solving The method described in Appendix 1.

[0174] (Appendix 7) Said ρ log , Φ, or ρ matrix 7. The method of claim 6, wherein one or more of are obtained or derived from one or more well log logs.

[0175] (Appendix 8) Determining an acoustic slowness of the fluid in the pore space includes: Δt log = bulk acoustic slowness in the rock formation (μs / ft), Φ = porosity of the rock formation expressed as a ratio, Δtfluid = acoustic slowness of the fluid contained within the pore space of the rock formation (μs / ft), 1-Φ=volume fraction of rock in the formation expressed as a ratio, and Δt matrix = acoustic slowness of the rock matrix, Then, Δt log =(Φ)*Δt fluid +(1-Φ)*Δt matrix Using the acoustic slowness equation, Δt fluid calculating the acoustic slowness of the fluid in the pore space by solving The method described in Appendix 1.

[0176] (Appendix 9) Δt log , Φ, or Δt matrix 9. The method of claim 8, wherein one or more of are obtained or derived from one or more well log logs.

[0177] (Appendix 10) 2. The method of claim 1, wherein determining the type of fluid in the pore space includes correlating the fluid density and acoustic slowness of the fluid in the pore space with known combinations of fluid density and acoustic slowness of one or more of hydrogen, methane, hydrogen, helium, water, or carbon dioxide.

[0178] (Appendix 11) 2. The method of claim 1, further comprising identifying a geological area of ​​interest.

[0179] (Appendix 12) 2. The method of claim 1, further comprising determining a relative amount of the fluid within the rock formation.

[0180] (Appendix 13) 2. The method of claim 1, further comprising the step of flagging a determination of the presence of the selected fluid type.

[0181] (Appendix 14) 14. The method of claim 13, wherein flagging the presence of the selected fluid type includes providing a list of subsurface sections having physical characteristics indicative of one or more of the presence of the selected fluid type or the relative amount of the selected fluid type.

[0182] (Appendix 15) 14. The method of claim 13, wherein the selected fluid type comprises one or more of hydrogen, helium, or carbon dioxide.

[0183] (Appendix 16) 2. The method of claim 1, further comprising one or more of the steps of planning or drilling one or more additional wells at locations determined to indicate the presence of one or more selected fluid types.

[0184] (Appendix 17) 1. A system for identifying subsurface fluids in a geological formation, the system comprising: a computing device having a processor and a memory storage device operably coupled to the processor, the memory storage device having one or more operational programs including machine readable and executable instructions for identifying one or more selected fluids in a rock formation based on data from one or more well log logs, the processor configured to read and execute the one or more operational programs; the data from the one or more well log logs is indicative of one or more of a rock matrix type, a porosity of the rock formation, a fluid density of a fluid within the pore space of the rock formation, or an acoustic slowness of the fluid within the pore space of the rock formation; system.

[0185] (Appendix 18) said one or more operating programs: determining the rock matrix type of the rock formations in a geological region of interest; determining the porosity of the rock formation; determining the fluid density of the fluid within the pore space of the rock formation; determining the acoustic slowness of the fluid in the pore space; determining a fluid type of the fluid in the pore space; including machine-readable and executable instructions for performing 18. The system of claim 17.

[0186] (Appendix 19) 20. The system of claim 18, wherein the instructions for determining a rock matrix type of rock formations in the geological region of interest include instructions for examining one or more well log logs for physical properties indicative of rock matrix type.

[0187] (Appendix 20) 20. The system of claim 18, wherein the instructions for determining the porosity of the rock formation include instructions for obtaining porosity data from one or more well log logs.

[0188] (Appendix 21) The instructions for executing determining the fluid density of the fluid in the pore space include: ρ log = Bulk density (g / cm) measured by density logging tool 3 ), Φ=porosity of the rock formation expressed as a ratio; ρ fluid = fluid density (g / cm) of the fluid contained within the pore space of the rock formation 3 ), 1-Φ=volume fraction of rock matrix in the rock formation expressed as a ratio; and ρ matrix = density of the rock matrix (g / cm 3 ), Then, ρ log =(Φ)*ρ fluid +(1-Φ)*ρ matrix Using the equation for ρ fluid and calculating the fluid density of the fluid in the pore space by solving: 19. The system of claim 18.

[0189] (Appendix 22) The instructions for executing the step of determining the acoustic slowness of the fluid in the pore space include: Δt log = bulk acoustic slowness in the rock formation (μs / ft), Φ=porosity of the rock formation expressed as a ratio; Δt fluid = acoustic slowness (μs / ft) of the fluid contained within the pore space of the rock formation, 1-Φ=volume fraction of rock in the formation expressed as a ratio; and Δt matrix = acoustic slowness of the rock matrix, Then, Δt log =(Φ)*Δt fluid +(1-Φ)*Δt matrix Using the equation for Δt fluid and calculating the acoustic slowness of the fluid in the pore space by solving 19. The system of claim 18.

[0190] (Appendix 23) 19. The system of claim 18, wherein the instructions for determining a fluid type in the pore space include instructions for correlating a fluid density and acoustic slowness of the fluid in the pore space to a known combination of fluid density and acoustic slowness of one or more of hydrogen, methane, hydrogen, helium, water, or carbon dioxide.

[0191] (Appendix 24) 20. The system of claim 18, wherein the instructions include instructions for executing identifying a geological region of interest having a formation containing the rock matrix therein.

[0192] (Appendix 25) 20. The system of claim 18, wherein the instructions include instructions for executing determining a relative amount of the fluid in the pore space.

[0193] (Appendix 26) 20. The system of claim 18, wherein the instructions include instructions to execute flagging a determination of the presence of a selected fluid type.

[0194] (Appendix 27) 27. The system of claim 26, wherein the selected fluid type includes one or more of hydrogen, helium, or carbon dioxide.

[0195] (Appendix 28) 18. The system of claim 17, further comprising a network connection in electronic communication with the computing device and one or more electronic data sources external to the computing device, the one or more electronic data sources including one or more well log logs therein.

[0196] (Appendix 29) 29. The system of claim 28, wherein the one or more electronic data sources external to the computing device include a server, a cloud-based memory storage device, or an additional computing device located remotely from the computing device and having one or more well log logs stored thereon.

[0197] (Appendix 30) 1. A method for identifying subsurface fluids in a geological formation, the method comprising: identifying a geological area of ​​interest; determining a rock matrix type of rock formations in the geological region of interest; determining the porosity of the rock formation; determining a fluid density of a fluid within the pore space of the rock formation; determining an acoustic slowness of the fluid in the pore space; determining a fluid type of the fluid in the pore space; setting a flag indicating the presence of the selected fluid type; The method includes:

[0198] (Appendix 31) 31. The method of claim 30, wherein the steps of determining a rock matrix type of a rock formation in the geological region of interest, determining a porosity of the rock formation, determining the fluid density of the fluid in the pore space of the rock formation, determining the acoustic slowness of the fluid in the pore space, determining the fluid type of the fluid in the pore space, and flagging the presence of the selected fluid type are repeated at multiple subterranean sections in the formation using well log data to identify one or more locations of the selected fluid type throughout the formation.

[0199] (Appendix 32) 32. The method of claim 31, further comprising determining a relative amount of the selected fluid type within the rock formation.

[0200] (Appendix 33) 33. The method of claim 32, wherein the steps of determining a rock matrix type of the rock formation in the geological region of interest, determining a porosity of the rock formation, determining a fluid density of a fluid in the pore space of the rock formation, determining an acoustic slowness of a fluid in the pore space, determining a fluid type in the pore space, flagging selected fluid types, and determining a relative amount of the selected fluid type in the rock formation are repeated over time within a subterranean formation, each time using new well log data to identify depletion, sequestration, or storage of the selected fluid type within the rock formation.

[0201] (Appendix 34) 31. The method of claim 30, further comprising one or more of the steps of planning or drilling one or more wells at locations where the presence of the selected fluid type is flagged.

[0202] (Appendix 35) 1. A method for distinguishing hydrogen from other subsurface fluids, the method comprising: using a geophysical acoustic log to distinguish hydrogen from hydrocarbon fluids or other subsurface fluids; distinguishing hydrogen from water using a geophysical density log; The method includes:

[0203] (Appendix 36) 1. A method for distinguishing carbon dioxide from other subsurface fluids, the method comprising: using the acoustic geophysical logs to distinguish the carbon dioxide from hydrocarbon fluids or other subsurface fluids; distinguishing the carbon dioxide from water using a geophysical density log; The method includes:

[0204] (Appendix 37) 1. A method for distinguishing helium from other subsurface fluids, the method comprising: using the geophysical acoustic logging logs to distinguish the helium from hydrocarbon fluids or other subsurface fluids; distinguishing the helium from water using a geophysical density log; The method includes:

[0205] (Appendix 38) 1. A method for distinguishing hydrogen injected into a subsurface formation from other subsurface fluids, the method comprising: using geophysical and acoustic well logs to distinguish hydrogen from various industrial sources from hydrocarbon fluids or other subsurface fluids; using geophysical density logs to distinguish hydrogen from water obtained from various industrial sources; The method includes:

[0206] (Appendix 39) 1. A method for distinguishing carbon dioxide injected into a subsurface formation in a gaseous or supercritical state from other subsurface fluids, the method comprising: using geophysical and acoustic well logs to distinguish carbon dioxide from various industrial sources from hydrocarbon fluids or other subsurface fluids; Using geophysical density well logs to distinguish carbon dioxide from water obtained from various industrial sources; The method includes:

[0207] (Appendix 40) 1. A method for identifying and quantifying hydrogen in a subsurface formation, the method comprising: identifying and quantifying hydrogen in the subsurface formation using geophysical logs, including one or more of acoustic or density logs; The method includes:

[0208] (Appendix 41) 1. A method for identifying and quantifying carbon dioxide in a subsurface formation, the method comprising: identifying and quantifying carbon dioxide in the subsurface formation using geophysical logs, including one or more of acoustic or density logs; The method includes:

[0209] (Appendix 42) 1. A method for identifying and quantifying helium in a subsurface geological formation, the method comprising: identifying and quantifying helium in the subsurface formation using geophysical logs, including one or more of an acoustic log or a density log; The method includes:

[0210] (Appendix 43) 1. A method of exploring for hydrogen in a subsurface formation, the method comprising: identifying accumulations of hydrogen in said subsurface formation using geophysical log patterns characteristic of hydrogen; The method includes:

[0211] (Appendix 44) 1. A method for exploring for carbon dioxide in a subsurface formation, the method comprising: identifying accumulations of carbon dioxide in said subsurface formation using geophysical log patterns characteristic of carbon dioxide; The method includes:

[0212] (Appendix 45) 1. A method of detecting helium in a subsurface formation, the method comprising: identifying accumulations of helium in said subsurface formation using geophysical log patterns characteristic of helium; The method includes:

[0213] (Appendix 46) 1. A method for verifying storage of hydrogen in an underground reservoir, the method comprising: identifying hydrogen accumulation in said subsurface reservoir using a geophysical log pattern characteristic of hydrogen; The method includes:

[0214] (Appendix 47) 1. A method for verifying storage of carbon dioxide in an underground reservoir, the method comprising: identifying carbon dioxide accumulation in the subsurface reservoir using geophysical log patterns characteristic of carbon dioxide; The method includes:

[0215] (Appendix 48) 1. A method for verifying carbon dioxide sequestration in subsurface minerals, the method comprising: identifying carbon dioxide accumulations in said subsurface minerals using geophysical log patterns characteristic of carbon dioxide; The method includes:

[0216] (Appendix 49) 1. A computer-assisted method for distinguishing hydrogen from other subsurface fluids, the method comprising: automatically distinguishing, by a computing device, the hydrogen from nitrogen, carbon dioxide, or hydrocarbon fluids using the geophysical acoustic logging logs; automatically distinguishing hydrogen from water using a physical density log with a computing device; The method includes:

[0217] (Appendix 50) 1. A computer-assisted method for identifying and quantifying hydrogen in a subsurface formation, the method comprising: automatically using the geophysical logs, including one or more of an acoustic log or a density log, to identify and quantify hydrogen in the subsurface formation; The method includes:

[0218] (Appendix 51) 1. A computer-aided method for exploring for hydrogen in a subsurface formation, the method comprising: automatically identifying accumulations of hydrogen in said subterranean formation by a computer assisted operating program configured to automatically use well geophysical log patterns characteristic of hydrogen to search existing or stored well geophysical logs for the presence of hydrogen in said subterranean formation by a computing device; The method includes:

[0219] (Appendix 52) 1. A computer-assisted method for distinguishing carbon dioxide from other subsurface fluids, the method comprising: automatically distinguishing carbon dioxide from hydrocarbon fluids using geophysical and acoustic well logs with a computing device; automatically differentiating the carbon dioxide from water using the geophysical density log with a computing device; The method includes:

[0220] (Appendix 53) 1. A computer-assisted method for identifying and quantifying carbon dioxide in a subsurface formation, the method comprising: automatically using, by a computing device, geophysical logs, including one or more of an acoustic log or a density log, to identify and quantify carbon dioxide in the subsurface formation; The method includes:

[0221] (Appendix 54) 1. A computer-assisted method for exploring for carbon dioxide in a subsurface formation, the method comprising: automatically using, by a computing device, geophysical log patterns characteristic of carbon dioxide to identify accumulations of carbon dioxide in the subsurface formation; searching, by a computing device, existing or stored geophysical well logs for the presence of carbon dioxide, automatically using an operating program stored on said computing device; The method includes:

[0222] (Appendix 55) 1. A computer-aided method for distinguishing helium from other subsurface fluids, the method comprising: automatically distinguishing, by a computing device, the helium from the hydrocarbon fluid using the geophysical acoustic logging logs; automatically differentiating, by a computing device, the helium from water using the geophysical density log; The method includes:

[0223] (Appendix 56) 1. A computer-assisted method for identifying and quantifying helium in a subsurface formation, the method comprising: automatically using, by a computing device, geophysical logs, including one or more of an acoustic log or a density log, to identify and quantify helium in the subsurface formation; The method includes:

[0224] (Appendix 57) 1. A computer-aided method for detecting helium in a subsurface formation, the method comprising: automatically using, by a computing device, geophysical log patterns characteristic of helium to identify accumulations of helium in the subsurface formation; searching, by a computing device, existing or stored well geophysical logs for the presence of helium automatically using an operating program stored on said computing device; The method includes:

[0225] (Appendix 58) 1. A method for identifying subsurface hydrogen, helium, or carbon dioxide, the method comprising: automatically analyzing geophysical log images or borehole images using an image recognition module for patterns characteristic of subsurface hydrogen, helium, or carbon dioxide to identify said subsurface accumulations of hydrogen, helium, or carbon dioxide; A step of outputting the analysis results of the geophysical logging log image; The method includes:

[0226] (Appendix 59) 1. A method for identifying subsurface hydrogen, helium, or carbon dioxide, the method comprising: receiving information including imaged or digitized characteristics of a well log; estimating the likelihood that a characteristic of the well log indicates an accumulation of hydrogen or carbon dioxide in the subsurface; determining whether the estimated likelihood meets a predetermined threshold for the likelihood of the existence of a subsurface accumulation of hydrogen, helium, or carbon dioxide; in response to determining whether the estimated likelihood meets a predetermined threshold, outputting an indication that the characteristic of the well log is indicative of the presence or absence of a subsurface accumulation of hydrogen, helium, or carbon dioxide; The method includes:

Claims

1. A method for drilling a borehole to the depth of subsurface hydrogen in a rock layer, wherein the method is: The process of identifying the geological area of ​​interest, A step of determining the rock matrix type of the rock layer in the geological region of interest, A step of determining the porosity of the rock layer, A step of determining the fluid density of the fluid in the pore space of the rock layer, A step of determining the acoustic slowness of the fluid in the pore space, A step of distinguishing the subsurface hydrogen from the hydrocarbon fluid or other subsurface fluid in the fluid using a physical acoustic logging log, A step of distinguishing the underground hydrogen from the water in the fluid using a physical density logging log, A flagging step, comprising the step of flagging distinguished subsurface hydrogen, which includes the step of providing the depth within the rock layer having physical properties indicating the presence or amount of distinguished subsurface hydrogen, In response to the step of determining the distinguished underground hydrogen, the steps include drilling a borehole in the rock layer to the depth of the distinguished underground hydrogen, A method that includes this.

2. The method according to claim 1, wherein the steps of determining the rock matrix type of the rock layer in the geological region of interest, determining the porosity of the rock layer, determining the fluid density of the fluid in the pore space of the rock layer, and determining the acoustic slowness of the fluid in the pore space are repeated in a plurality of subsurface sections within a subsurface formation using well logging log data to identify one or more locations of subsurface hydrogen throughout the formation.

3. The method according to claim 1, further comprising the step of determining the relative amount of subsurface hydrogen within the rock layer.

4. The method according to claim 1, wherein the steps of determining the rock matrix type of the rock layer in the geological region of interest, determining the porosity of the rock layer, determining the fluid density of the fluid in the pore space of the rock layer, determining the acoustic slowness of the fluid in the pore space, and determining the relative amount of subsurface hydrogen in the rock layer are repeated over time in the subsurface formation using new well logging log data each time in order to identify depletion or storage of subsurface hydrogen in the rock layer.

5. The method according to claim 1, further comprising one or more steps of planning or drilling one or more wells at locations where the presence of underground hydrogen is flagged.

6. A system for drilling a borehole to the depth of subsurface hydrogen in a rock layer, wherein the system comprises: A computing device comprising a processor and a memory storage device operably coupled to the processor, wherein the memory storage device stores one or more operation programs including machine-readable and executable instructions, and when such programs are executed, the computing device To determine the rock matrix type of the aforementioned rock layer in the geological region of interest, To determine the porosity of the aforementioned rock layer, To determine the fluid density of the fluid within the pore space of the rock layer, To determine the acoustic slowness of the fluid in the aforementioned pore space, Distinguishing the subsurface hydrogen from the hydrocarbon fluid or other subsurface fluids in the fluid using a physical acoustic logging log, Distinguishing the underground hydrogen from the water in the fluid using a physical density logging log, Flagging distinguished subsurface hydrogen, including providing a depth within the rock layer having physical properties indicating the presence or relative amount of the distinguished subsurface hydrogen; A drilling rig configured to drill the borehole in the geological region of interest to the depth of the distinguished subsurface hydrogen in response to the computing device that determines the distinguished subsurface hydrogen, Execute system.

7. The system according to claim 6, wherein the machine-readable and executable command for determining the rock matrix type of a rock formation in the geological region of interest includes a command for examining one or more well logging logs for physical properties indicating the rock matrix type.

8. The system according to claim 6, wherein the machine-readable and executable command for determining the porosity of the rock layer includes a command for obtaining porosity data from one or more well logging logs.

9. The machine-readable and executable instruction for determining the fluid density of the fluid in the pore space is: ρ ｌｏｇ = Bulk density (g / cm³) measured with a density logging tool ３ ), Φ = porosity of the rock layer expressed as a ratio, ρ ｆｌｕｉｄ = Fluid density of the fluid contained within the pore space of the rock layer (g / cm³) ３ ), The volume fraction of the rock matrix in the aforementioned rock layer, expressed as 1 - Φ = ratio, and ρ ｍａｔｒｉｘ = Density of the aforementioned rock matrix (g / cm³) ３ ), When ρ ｌｏｇ =(Φ)*ρ ｆｌｕｉｄ +(1 - Φ)*ρ ｍａｔｒｉｘ Using the equation of ρ ｆｌｕｉｄ Execute instructions to calculate the fluid density of the fluid in the pore space by solving for ρ The system according to claim 6.

10. The machine-readable and executable instruction for determining the acoustic slowness of the fluid in the pore space is: Δt ｌｏｇ = Bulk acoustic slowness (μs / ft) within the aforementioned rock layer, Φ = porosity of the rock layer expressed as a ratio, Δt ｆｌｕｉｄ = The acoustic slowness (μs / ft) of the fluid contained within the pore space of the rock layer, 1 - Φ = the volume fraction of rock in the aforementioned rock layer expressed as a ratio, and Δt ｍａｔｒｉｘ = Acoustic slowness of the aforementioned rock matrix, When this is the case, Δt ｌｏｇ = (Φ) * Δt ｆｌｕｉｄ +(1-Φ)*Δt ｍａｔｒｉｘ Using the equation Δt ｆｌｕｉｄ The instruction includes a command to perform the calculation of the acoustic slowness of a fluid in a pore space by solving the following equation: The system according to claim 6.

11. The system according to claim 6, wherein the computing device is further configured to perform a determination of the presence of subsurface hydrogen in the pore space, and the machine-readable executable command for performing a determination of the presence of subsurface hydrogen in the pore space includes a command for performing a determination of the fluid density and acoustic slowness of the fluid in the pore space to a known combination of the fluid density and acoustic slowness of one or more of hydrogen, methane, hydrogen, helium, water, or carbon dioxide.

12. The system according to claim 6, wherein the machine-readable and executable instruction includes an instruction that performs the task of identifying a geological region of interest having a strata containing the rock matrix inside.

13. The system according to claim 6, wherein the machine-readable and executable instruction includes an instruction for determining the relative amount of ground hydrogen in the pore space.

14. The system according to claim 6, wherein the distinguished subsurface hydrogen within the rock layer is based on data from one or more well logging logs, the data from one or more well logging logs indicating one or more rock matrix types, the porosity of the rock layer, the fluid density of the fluid in the pore space of the rock layer, or the acoustic slowness of the fluid in the pore space of the rock layer.

15. The system according to claim 6, further comprising a communication interface for electronic communication with the computing device and one or more electronic data sources remote from the computing device.

16. The system according to claim 15, wherein one or more electronic data sources store one or more well logging logs.

17. The system according to claim 16, wherein the one or more electronic data sources include a server, a cloud-based memory storage device, or an additional computing device located remotely from the computing device.

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