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Background of the sister

Detection models generally relate to the identification of hydrocarbon-rich spots. More specifically, detection models relate to methods for identifying hydrocarbon-rich spots in hydrocarbon-bearing formations using carbon dioxide geochemistry.

<p dir="rtl">5 Carbon dioxide (CO2) is a common non-hydrocarbon component associated with oil and natural gas. It is found in subsurface areas worldwide in a variety of geological formations. The abundance of CO2 trapped in hydrocarbon-bearing formations (e.g., impermeable formations) varies from trace amounts to the entire amount of the resulting fluid.</p>

<p dir="rtl">10 The CO2 abundance in a hydrocarbon-bearing formation is a factor to be considered during reservoir evaluation, reservoir simulation, field development, and facility design. For example, CO2 content in the petroleum industry is typically measured by performing gas compositional analysis on fluid samples during formation testing, well testing, reservoir stimulation, and production. Fluid samples are collected using a downhole sampling tool or collected at the wellhead or separator located on the</p>

<p dir="rtl">15 The surface.</p>

CO2 content measurements are used in various ways in the petroleum industry. For example, CO2 content data are used as inputs to model pressure, volume,

For inventory management. pressure, volume, and temperature (PVT) are taken.

Carbon dioxide content data is considered in relation to the design of the facility to mitigate corrosion due to

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The dissolved form of carbon dioxide corroding against steel and carbon-based components used to produce hydrocarbons. The carbon dioxide content data is taken into account to reduce the carbon dioxide in the gas produced so that the natural gas market requirements are met. Explorers use specific geochemical data for carbon dioxide (e.g. carbon dioxide content data

<p dir="rtl">5 Carbon isotopic signature data (to trace the source and map the distribution of CO2 to avoid potential drilling that involves abundant CO2. Also, explorers and reservoir engineers use specific CO2 geochemical data to accurately assess hydrocarbon reserves and predict reservoir partitioning.</p>

Inorganic Origin of CO2 and Its Indication for Sweet Spots in Document Reveals

Tight Formations, North West Saudi Arabia – (10/15/2017), 10

XP055757563 Gas from the lower Paleozoic tight sandstones of the Sarh and upper Qassim formations in northwestern Saudi Arabia is generally observed to be sourced from marine organic matter of the second type of Qusaiby oil shale. Gas from high initial production (IP) wells in the area shares the characteristics of

<p dir="rtl">15 Common features are high gas dryness and relatively heavy carbon isotopic composition (δ 13 C) of methane. Regional variations in gas composition and distribution appear to reflect regional maturity control of the Qusaybah source rocks. Moisture isotope inversions and partial inversions versus carbon number have been identified in high IP gases from these tight formations. Some low IP wells, however, have high gas maturity, with core/inversion isotope profiles, indicating</p>

<p dir="rtl">20 It indicates that another factor(s), perhaps related to reservoir quality, must be considered when searching for gas-pumping zones.</p>

The distinguishing features we found—other than gas maturity, dryness, and isotopic inversions—were the isotopic composition and composition of carbon dioxide (CO2). The concentrations of CO2 in the total gas are higher than in high-production wells (IP 9%).

<p dir="rtl">25 15%), compared to low primary production wells (&gt;9%). The δ 13C of CO2 in</p>

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These tight sandstones, as well as the overlying reed shale, are all heavier than -10‰, indicating an inorganic origin. Mineralogical and petrographic associations in these tight sandstones, such as engraving and dissolution of carbonate cements, e.g., siderite, indicate derivation of CO2 from carbonate dissolution/decomposition. In contrast, the δ 13C of CO2

<p dir="rtl">5 Carbon generated from the thermal decomposition of gold from a kerogen concentrate in a reed is</p>

The average is about -30‰, providing further evidence for the inorganic origin of the CO2 in the tight sands. Upon thermal decomposition, large amounts of CO2 were generated, which could provide a precursor for the stabilization of carbonates in tight sandstones. Subsequent dissolution and/or thermal decomposition would cement the carbonates—in response to changes in geochemical equilibrium.

<p dir="rtl">10 Or anomalous geothermal events — creating secondary porosity to trap more gas and enhance well deliverability. Inorganic CO2 and high gas maturity can synergistically provide a practical tool for identifying rich spots in tight formations. Future steps will consider source rock kinematics and reservoir thermodynamics to understand subsurface CO2 generation and distribution, as well as incorporate CO2 as a key factor in reservoir quality models.</p>

<p dir="rtl">15 General description of the invention</p>

Detection models generally relate to the identification of hydrocarbon-rich spots. More specifically, detection models relate to methods for identifying hydrocarbon-rich spots in hydrocarbon-bearing formations using carbon dioxide geochemistry.

The detection models provide a method for evaluating the hydrocarbon-bearing formation. The method includes a step 20 of identifying the hydrocarbon-rich spot. The identification step includes determining the carbon dioxide content

Carbon of a gas sample recovered from a hydrocarbon-bearing formation. The identification step involves determining the carbon dioxide isotopic fingerprint of the gas sample.

In some embodiments, the molar percentage of carbon dioxide content in the gas sample ranges from 9 percent (%) to 20%. In some embodiments, the carbon dioxide isotopic signature of the gas sample

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The gas has a δ13C value greater than -10 per thousand (‰). In some embodiments, the determination step also includes determining a CO2 content cutoff range corresponding to the hydrocarbon-rich spot. In some embodiments, the cutoff range has a mole percentage ranging from 9% to 20%. In some embodiments, the determination step also includes obtaining a gas flow rate for the bearing formation

<p dir="rtl">5 For hydrocarbons. In some embodiments, the gas flow rate is greater than 283,168 standard cubic meters per day. In some embodiments, the hydrocarbon-bearing formation is an impermeable formation. In some embodiments, the gas sample is recovered by wireline formation testing or drill stem testing.</p>

The detection models also provide a method for evaluating the formation of a hydrocarbon carrier. The method includes a step

<p dir="rtl">10 Hydrocarbon-rich spot identification. The identification step includes determining the CO2 content of a first gas sample recovered from an exploration well of the hydrocarbon-bearing formation. The identification step includes determining the CO2 isotopic signature of the first gas sample. The identification step includes obtaining the gas flow rate in the exploration well. The identification step includes determining the CO2 content of a second gas sample recovered from an appraisal well or a production well.</p>

<p dir="rtl">15 In some embodiments, the CO2 content of the initial gas sample has a mole percentage ranging from 9% to 20%. In some embodiments, the CO2 isotopic signature of the initial gas sample has a δ13C value greater than -10‰. In some embodiments, the determination step also includes determining a CO2 content cutoff range corresponding to the hydrocarbon-rich spot. In some embodiments, the cutoff range has a mole percentage ranging from 9% to 20%. In some embodiments, the</p>

<p dir="rtl">20 The gas flow to the exploration well is greater than 283,168 scf/day. In some embodiments, the CO2 content of the second gas sample has a mole percentage ranging from 9% to 20%. In some embodiments, the determination step also includes determining the CO2 isotopic signature of the second gas sample. In some embodiments, the CO2 isotopic signature of the second gas sample has a δ13C value greater than -10‰. In some embodiments, the hydrocarbon-bearing formation is</p>

<p dir="rtl">25 It is an impermeable configuration. In some embodiments, the first gas sample is recovered by testing</p>

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Wireline formation or drill stem test. In some embodiments, the second gas sample is recovered by wireline formation test.

The detection embodiments also provide a method for producing hydrocarbon from a hydrocarbon-bearing formation. The method includes the step of identifying the hydrocarbon-rich spot by determining the carbon dioxide content.

<p dir="rtl">5 A gas sample recovered from a hydrocarbon-bearing formation and determination of the isotopic signature of carbon dioxide in the gas sample. The method includes a step of producing hydrocarbon in the hydrocarbon-rich spot.</p>

In some embodiments, the carbon dioxide content of the gas sample has a mole percentage ranging from 9% to 20%. In some embodiments, the isotopic signature of the carbon dioxide in the gas sample has

<p dir="rtl">10 The δ13C value is greater than -10‰. In some embodiments, the determination step also includes determining a CO2 content cutoff range corresponding to the hydrocarbon-rich spot. In some embodiments, the cutoff range has a mole percentage ranging from 9% to 20%. In some embodiments, the determination step also includes obtaining a gas flow rate for the hydrocarbon-bearing formation. In some embodiments, the gas flow rate is greater than 283168 scf/day. In some embodiments, the determination step also includes</p>

<p dir="rtl">15 The method also includes the step of stimulating the hydrocarbon-bearing formation. In some embodiments, the hydrocarbon-bearing formation is an impermeable formation. In some embodiments, the gas sample is recovered by wireline formation testing or drill stem testing.</p>

Brief explanation of the drawings

Thus, this method is achieved and can be understood in detail, and in it the features, aspects and characteristics will become clear.

<p dir="rtl">20 The above mentioned models of this disclosure as well as others, more description can be obtained</p>

Specifically for the disclosure which has been briefly summarized previously with reference to the embodiments illustrated in the drawings which form part of this specification. It is noted, however, that the accompanying drawings illustrate only certain embodiments of the disclosure and cannot be considered as limiting the scope of the disclosure. The disclosure recognizes other embodiments having the same

Effectiveness.

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Figure 1 is a schematic diagram illustrating a process for identifying the hydrocarbon-rich spot of a hydrocarbon-bearing formation according to the detection model threshold.

Figure 2 is a schematic diagram illustrating a process for identifying the hydrocarbon-rich spot of a hydrocarbon-bearing formation according to the detection model threshold.

<p dir="rtl">5 Figure 3 is a schematic diagram illustrating the process for identifying the hydrocarbon-rich spot of a hydrocarbon-bearing formation according to the detection model threshold.</p>

Figure 4 is a graph showing the geochemical parameters of CO2 recovered from multiple target zones in selected wells for two potential formations according to the detection model threshold.

<p dir="rtl">10 Figure 5A is a photogram illustrating a petrographic analysis of one of four sandstone samples recovered from a well selected for a potential formation according to the detection model threshold. Figure 5B is a photogram illustrating a petrographic analysis of one of four sandstone samples recovered from a well selected for a potential formation according to the detection model threshold. Figure 5C is a photogram illustrating a petrographic analysis of one of four sandstone samples recovered from a well selected for a potential formation according to the detection model threshold. Figure 5D is a photogram</p>

<p dir="rtl">15 Photo Arvi shows a petrographic analysis of one of four sandstone samples recovered from the Mukhtar well.</p>

For a possible formation according to the detection model limits. Figures 5e-h are enlarged photogrammetric drawings of the selected areas in Figures 5a-d, respectively.

Figure 6 is a graph showing the geochemical parameters of CO2 recovered from multiple target zones in selected wells for two potential formations and the specific parameters.

<p dir="rtl">20 For the selected well productivity of 10 ...</p>

According to the attached figures, similar components, features, or both may have a similar reference mark.

Detailed description:

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The disclosure refers to specific features, including steps of a method or process. It is understood by those skilled in the art that the disclosure is not limited to or by the description of embodiments specified in the specification. The subject matter of this disclosure is limited only by the spirit of the specification and the accompanying claims.

Skilled professionals in this field also understand that the terms used to describe specific models do not limit the scope of

<p dir="rtl">5 Or the scope of this disclosure. In interpreting the specification and the accompanying claims, all terms should be interpreted in the broadest possible way consistent with the context of each term. All technical and scientific terms used in this specification and the accompanying claims have the meaning normally understood by a person of ordinary skill in the art to which this disclosure pertains, unless otherwise specified.</p>

<p dir="rtl">10 Although the disclosure is described in relation to specific attributes, it should be understood that attributes and attribute models may be combined with other attributes and attribute models of these attributes.</p>

Although the disclosure is described in detail, it should be understood that various changes, modifications and adjustments can be made without deviating from the principle and scope of the disclosure. Accordingly, the scope of the present disclosure should be determined by the following claims and their appropriate legal equivalents.

<p dir="rtl">15 As used throughout the Disclosure, the singular forms “an,” “a,” and “the” include plural references unless the context clearly indicates otherwise.</p>

As used throughout the disclosure, the term “approximately” includes +/- 5% of the reported amount. As used throughout the disclosure, the term “material” includes +/- 10% of the reported amount.

<p dir="rtl">20 As used throughout the disclosure, the terms “includes,” “contains,” “includes,” and all other grammatical variations are intended to have an open-ended, non-restrictive meaning and do not exclude additional elements, components, or steps. Disclosure models may appropriately “include,” “consist of,” or “substantially consist of” the limited features discovered, and may be exercised in the absence of one of the</p>

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Undiscovered limited features. For example, a skilled person in this field may realize that certain steps can be combined into a single step.

As used throughout the disclosure, the terms “optional” or “optional” mean that the event or condition described below may or may not occur. The description includes situations that may

<p dir="rtl">5 In which a certain event or circumstance occurs and in which this event or circumstance may not occur.</p>

When a range of values ​​is provided in the specification or in the accompanying claims, the interval should be understood to include each value intervening between the upper and lower limits as well as the upper and lower limits. The disclosure includes and is related to ranges smaller than the interval subject to a specific exception provided.

<p dir="rtl">10 When a specification and accompanying claims refer to a method comprising two or more specified steps, the specified steps may be performed in any order or concurrently except where the context excludes this possibility.</p>

As used throughout the disclosure, terms such as “first” and “second” are arbitrarily defined and are intended only to distinguish between two or more components of the device. It should be understood that the terms “first”

<p dir="rtl">15 “Second” serves no other purpose and is not part of a name or description of the component, nor does it necessarily identify a location or relative position of the component. Furthermore, it should be understood that the mere use of the terms “first” and “second” does not require the existence of any “third” component, although such a possibility is envisaged within the scope of the present disclosure.</p>

As used throughout the disclosure, spatial terms describe the relative position of

<p dir="rtl">20 An element or set of elements in relation to another element or set of elements. Spatial relationships apply along the horizontal and vertical axes. Directional and relational terms, including the term "downhole" and similar terms, are reserved for descriptive convenience and are not restrictive unless otherwise indicated.</p>

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As used throughout exploration, the term “rich spot” refers to a target area, location, or area within a rarefied zone (an area where hydrocarbons accumulate) or reservoir that represents greater production or potential production relative to areas, locations, or acreage other than the target area, location, or acreage. Explorers and reservoir planners typically map rich spots so that drill holes are placed

<p dir="rtl">5 Well in productive or potentially productive reservoir areas.</p>

As used throughout the disclosure, the term “impermeable formation” refers to a relatively impermeable hydrocarbon-bearing formation that generally has a permeability of less than about 0.1 millidarcy (mD) and less than about 10% porosity. Non-exhaustive examples of impermeable formations include hydrocarbon-bearing sandstone formations, hydrocarbon-bearing limestone formations,

<p dir="rtl">10 And hydrocarbon-bearing shale formations.</p>

As used throughout the disclosure, the term “organic carbon dioxide” refers to carbon dioxide originating from an organic source. Conversely, as used herein throughout the disclosure, the term “inorganic carbon dioxide” refers to carbon dioxide originating from an inorganic source.

<p dir="rtl">15 The exploration models provide the use of CO2 geochemistry for field exploration and development.</p>

The hydrocarbon-rich spot of an impermeable formation can be identified based on information about the CO2 content and origin. The hydrocarbon-rich spot is representative of the improved storage capacity (corresponding to porosity) and conductivity (corresponding to permeability) for decision making in completing a production well.

<p dir="rtl">20 Carbonate-based minerals are abundant in impervious formations. For example, they can</p>

The sandstone composition may include calcite (CaCO3), dolomite (CaMg(CO3)), ankerite (Ca[Fe/Mg/Mn](CO3), or siderite (FeCO3). Carbonate-based minerals can act as cementing materials or framework grains in sandstones. Carbonates in these minerals can dissolve due to climatic changes.

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Certain factors in the geochemical environment over geologic history. For example, carbonates can dissolve due to organic acidification from maturation of organic matter, injection of carbon dioxide from external sources, diffusion of unsaturated water, increased temperature, or any combination of these factors. Carbonate dissolution is commonly observed in petrographic analysis and is suggested by certain post-diagenetic models.

<p dir="rtl">5 Dissolving carbonates can lead to the formation of gaseous carbon dioxide as shown in representative reactions (1) and (2):</p>

CaCO3(s) + 2H+(aq) ↔ Ca2+(aq) + HCO3–(aq)

)1(

2HCO3–(aq) ↔ H2O + CO2(g)

)2( 10

Both representative reactions (1) and (2) are reversible. In addition, the dissolution of carbonates (i.e., the right-hand side of both representative reactions (1) and (2)) creates additional pore volume, known as secondary porosity. Secondary porosity can plug some of the blocked pore throats to increase the permeability of the impermeable formation.

<p dir="rtl">15 In an impermeable formation, the gaseous CO2 generated will not escape from the formation but can be trapped within it. The trapped CO2 increases the formation pressure. The increased formation pressure can conserve the increased pore volume created by secondary porosity. The increased formation pressure can prevent the over-compression of the impermeable formation. The increased formation pressure can improve the reservoir quality and enhance the productivity of the impermeable hydrocarbon-bearing formation. According to</p>

<p dir="rtl">20 Therefore, carbon dioxide, a product of carbonate dissolution in impermeable formations, can act as a geochemical indicator to track the well productivity of an impermeable hydrocarbon-bearing formation and identify hydrocarbon-rich spots.</p>

From a geochemical perspective, sequestered CO2 can be classified as originating from an inorganic source. Examples of non-exhaustive sources of inorganic CO2 are:

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Sequestered CO2 includes CO2 from mantle degassing, volcanic activity, carbonate melting, and thermal decomposition of carbonate-based minerals. In contrast to inorganic sources, non-exhaustive examples of organic sources of sequestered CO2 include CO2 from oil and gas, coal conversion, hydrocarbon destruction, and bacteria.

<p dir="rtl">5 In some embodiments, the gas recovered from the impermeable formation may include carbon dioxide originating from an inorganic source. The carbon dioxide content of the gas (in terms of molar percentage) ranges from about 0% to about 100%, alternatively from about 5% to about 50%, or alternatively from about 9% to about 20%. For example, gas with a carbon dioxide content greater than about 5% may be indicative of the presence of carbon dioxide.</p>

<p dir="rtl">10 Inorganic carbon. In addition, gas with a carbon dioxide content greater than about 5% can be an indicator of carbonate dissolution in the impermeable formation. For example, gas with a carbon dioxide content ranging from about 15% to about 100% can be an indicator of inorganic carbon dioxide. In addition, gas with a carbon dioxide content ranging from about 15% to about 100% can be</p>

<p dir="rtl">15 It is an indication of carbonate dissolution in the impermeable formation or carbon dioxide sequestration from the mantle, or both.</p>

In some embodiments, the inorganic carbon dioxide present in the gas recovered from the unexposed formation has a typical primary isotopic signature. As used throughout the disclosure, the carbon isotopic signature of the inorganic carbon dioxide may be expressed using delta (δ) notation in units of

<p dir="rtl">20 In parts per thousand (in thousand, or ‰), as shown for example in equation (3):</p>

)3(

13C =

^{(1132 C}C⁾sample

^{(12 C}C⁾standard

× 1000

Where the word standard means a fixed reference material, for example Pee Dee Belemnite (PDB). Inorganic carbon dioxide can have a δ13C value greater than about -12‰, instead

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Greater than about -10‰, or alternatively greater than about -8‰. The carbon isotopic signature of the carbon dioxide of the gas recovered from the impervious formation is an indicator of the presence of inorganic carbon dioxide and therefore an indicator of carbonate dissolution in the impervious formation.

In some embodiments, certain well parameters such as gas flow rate and well flow pressure may be measured.

<p dir="rtl">5 Wellhead flowing pressure (WHFP) to determine the productivity of the well. If the well has a gas flow rate or WHFP, or both, greater than a predetermined value or values, hydrocarbons can usually be produced in an RSI well such that stimulation methods such as hydraulic fracturing and techniques such as horizontal or directional drilling will not be required. For example, a predetermined value for gas flow rate of about 2.83 million standard cubic meters/day for outlets</p>

<p dir="rtl">10 The preset value of the gas flow rate can be about 283168 standard cubic meters/day for medium ports (having a throat opening of about 0.5 microns to about 2.5 microns). The preset value of the gas flow rate can be about 283168 standard cubic meters/day for fine ports (having a throat opening of about 10 microns).</p>

<p dir="rtl">15 The preset value of gas flow rate can be about 2831 scf/day for nanoports (having a throat opening of 0.01 μm to 0.1 μm).</p>

Figure 1 illustrates the process 100 for identifying a hydrocarbon-rich spot for a hydrocarbon-bearing formation according to the detection model limit.

<p dir="rtl">20 In Block 102, the potential hydrocarbon-bearing formation is identified and evaluated. The subsurface structure of the potential formation is mapped using conventional methodologies such as seismology, geology, geochemistry, and well data. One or more target zones may be identified for testing information and fluid sampling. One or more exploratory wells may then be drilled from the surface into the target zone. Gaseous hydrocarbons may be detected as a result of gas or</p>

<p dir="rtl">25 Gas release when drilling an exploration well. However, gaseous hydrocarbon detection during drilling</p>

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Not necessarily an indicator of sustainable production. For example, a discovery could result in a false positive, as gaseous hydrocarbons are generated by a certain change in drilling conditions. A discovery could result in a false negative, as gaseous hydrocarbon readings may not provide information regarding the presence of petroleum. Additionally, a wireline well performance logging tool can be deployed to the target area to measure certain rock physics parameters such as porosity, permeability, and water saturation.

However, these parameters are not necessarily an indicator of sustainable production.

In block 104, a gas sample is recovered from the exploratory well. In some embodiments, a wireline formation testing (WFT) may be performed by deploying a probe into the exploratory well. The WFT probe reaches the target zone to retrieve the fluid sample back 10 to the surface. The fluid sample may include gaseous components. The gaseous components may include hydrocarbons and compounds other than hydrocarbons. In other embodiments, a drill stem testing (DST) may be performed to retrieve the fluid sample in the target zone. In still other embodiments, the fluid sample may be recovered at the surface by a wellhead or gas-oil separator.

<p dir="rtl">15 In block 106, at the well site or an off-site laboratory, conventional methodologies such as gas chromatography (GC) can be performed to separate the gaseous components from the recovered fluid sample in block 104. Methodologies such as GC can be performed to analyze the composition of the separated gas sample and, as a result, the CO2 content (in terms of molar percentage) of the gas sample can be determined. Also in block 106, conventional methodologies such as mass spectrometry can be performed to separate the gaseous components from the recovered fluid sample in block 104.</p>

For a second GC separation in combination with isotope-ratio mass spectrometry (IRMS) 20 isotopes

carbon dioxide from a gas sample and obtain the carbon isotopic signature of the separated carbon dioxide. In this way, the δ13C value of carbon dioxide can be determined. A person skilled in the art will recognize that different methodologies can be implemented to determine the composition of carbon dioxide in a gas sample. A person skilled in the art will also recognize that methodologies can be implemented

<p dir="rtl">25 Different methods to obtain the carbon isotopic fingerprint of a carbon dioxide sample.</p>

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In Block 108, the geochemical origin of the CO2 present in the gas sample of the exploratory well is determined using the CO2 content data and the carbon isotopic signature data obtained in Block 106. As a non-exhaustive example, CO2 is determined to be of inorganic origin if the δ13C value of the carbon isotopic signature of CO2 is

<p dir="rtl">5 Carbon dioxide is greater than about -10‰. As a non-exhaustive example, carbon dioxide is defined as being of organic origin if the carbon dioxide content (in molar percentage) is less than about 15% and the δ13C value of the carbon isotopic signature of carbon dioxide is less than about -10‰.</p>

In box 110, data on gas flow rate and WHFP in the wells are obtained.

<p dir="rtl">10 Selected. DST may be performed in one or more selected exploratory wells identified as containing inorganic CO2 in Block 108. In these models, DST may be performed to determine parameters related to well productivity such as gas flow rate and WHFT, which are indicative of a hydrocarbon-rich spot.</p>

In box 112, the cutoff range for carbon dioxide content is specified. As used in all

<p dir="rtl">15 Throughout the exploration, the cutoff range corresponds to a productive mixture of gaseous hydrocarbon and inorganic carbon dioxide and is indicative of a hydrocarbon-rich spot. The carbon dioxide content data obtained in Block 106 and the gas flow rate data obtained in Block 110 are analyzed in conjunction with a search for a positive correlation between the two parameters. The presence of a positive correlation is indicative of the presence of a hydrocarbon-rich spot in the tested exploration wells. As an example</p>

<p dir="rtl">20 Non-exhaustive, the minimum value of the CO2 cutoff range can be set at about 9% which corresponds to a tested bar having a minimum gas flow rate greater than about 283168 scf/d. As a non-exhaustive example, the maximum value of the CO2 cutoff range can be set at about 20% due to the reduction in the economic value of the hydrocarbon gas produced as the CO2 content increases. A person skilled in the art will recognize that the CO2 cutoff range</p>

<p dir="rtl">25 Carbon dioxide and minimum gas flow rate can vary depending on the geographic location,</p>

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Well test results, production strategy of hydrocarbon producers, and local, regional or global natural gas market.

Alternatively, in block 114, the hydrocarbon-rich spot may be determined. The gas flow rate or WHFP, or both, obtained from block 110 may be compared with a predetermined value or values.

<p dir="rtl">5 As a non-exhaustive example, a hydrocarbon-rich spot is identified if the gas flow rate obtained in Block 110 is greater than the predetermined value of approximately 283,168 scfd. A person skilled in the art will recognize that the predetermined gas flow rate can vary depending on the geographic location, well test results, the production strategy of the hydrocarbon producers, and the local, regional, or global natural gas market.</p>

<p dir="rtl">10 In Block 116, the well completion operation is carried out at the hydrocarbon-rich spot identified in Block 114. Hydrocarbons can be produced conventionally in an ARC well so that stimulation methods such as hydraulic fracturing, and methods such as horizontal or directional drilling, will not be required. Alternatively, if the gas flow rate obtained in Block 110 is less than the predetermined value shown for example in Block 114, stimulation methods such as hydraulic fracturing can be implemented.</p>

<p dir="rtl">15 On the well, with or without horizontal or directional drilling. Then, following the process described in Boxes 110 and 114, data regarding the gas flow rate or WHFP, or both, of the stimulated well can be obtained to determine whether the stimulated well is productive. If so, a well completion operation is performed at the stimulated well and hydrocarbons can be produced.</p>

Figure 2 illustrates the 200 process for identifying the hydrocarbon-rich spot of a hydrocarbon-bearing formation.

<p dir="rtl">20 According to the detection model limits.</p>

In block 204, a gas sample is recovered from an appraisal well or production well of the potential formation as shown for example in block 102. In some embodiments, the WFT may be performed by deploying a probe into the appraisal well or production well. The WFT probe reaches the target zone

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To recover the fluid sample back to the surface. The fluid sample may contain gaseous components. The gaseous components may include hydrocarbons and compounds other than hydrocarbons.

In block 206, at the well site or an off-site laboratory, conventional methodologies such as GC can be implemented to separate gaseous components from the fluid sample recovered in block 204.

<p dir="rtl">5 Such as GC to analyze the composition of the separated gas sample and as a result, the CO2 content (in terms of molar percentage) of the gas sample can be determined. Optionally, conventional methodologies such as IRMS can be performed in conjunction with GC to separate the CO2 from the gas sample and obtain the carbon isotopic fingerprint of the separated CO2. In this way, the δ13C value of CO2 can be determined. A person skilled in the art will realize that the different methodologies</p>

<p dir="rtl">10 It can be implemented to determine the carbon dioxide composition of a gas sample. A person skilled in the art will also realize that different methodologies can be implemented to obtain the carbon isotopic fingerprint of a carbon dioxide sample.</p>

In block 208, the hydrocarbon-rich spot is identified. The CO2 content data obtained in block 206 are compared with the CO2 cutoff range determined in block 15 112. Because the potential formation in block 112 is identified as having a positive correlation between

CO2 content and gas flow rate are indicators of a hydrocarbon-rich spot. It is not necessary to perform carbon isotope analysis or DST to obtain gas flow rate and WHFP. As a non-exhaustive example, a hydrocarbon-rich spot is identified if the CO2 content of the gas sample in Block 206 falls within the representative CO2 cutoff range (defined in Block 20, 112) of about 9% to about 20%.

In Block 210, a well completion operation is being conducted in the hydrocarbon-rich spot identified in Block 208. Identification of the hydrocarbon-rich spot could enable conventional hydrocarbon production in an ARSI well without the use of stimulation methods such as hydraulic fracturing or techniques such as horizontal drilling or directional drilling.

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Figure 3 illustrates the process 300 for identifying the hydrocarbon-rich spot of a hydrocarbon-bearing formation according to the detection model limit.

In block 304, the CO2 content (in terms of mole percent) of the gas sample may be determined in situ using downhole fluid analysis (DFA). 5 DFA analysis may use a WFT fluid analyzer unit placed in the target area to recover the fluid sample via a WFT flowline. The WFT fluid analyzer may include an optical spectrometer to obtain compositional data, which includes CO2 content. A person skilled in the art will realize that various methodologies can be implemented to determine the CO2 composition of a fluid sample in situ.

<p dir="rtl">10 In block 306, the hydrocarbon-rich spot is identified. The CO2 content data obtained in block 304 are compared to the CO2 cutoff range identified in block 112. Because the potential formation in block 112 is identified as having a positive correlation between CO2 content and gas flow rate, which is indicative of a hydrocarbon-rich spot, it is not necessary to perform carbon isotope analysis or DST to obtain the gas flow rate.</p>

<p dir="rtl">15 Or WHFP. As a non-exhaustive example, a hydrocarbon-rich spot is identified if the CO2 content of the gas sample in Block 304 falls within the representative CO2 cutoff range (defined in Block 112) of about 9% to about 20%.</p>

In Block 308, the well completion operation is being conducted in the hydrocarbon-rich spot identified in Block 306. As noted in the disclosure, in these cases hydrocarbons can be produced in a conventional 20-well manner so that stimulation methods such as hydraulic fracturing and techniques such as horizontal or directional drilling are not necessary.

Examples

The following examples illustrate this disclosure and are provided for illustrative purposes only and are not intended to limit the scope of this disclosure.

The selection made by the attached protection elements.

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Example 1

Two potential gas hydrocarbon formations have been identified, Prospective Formation A and Prospective Formation B. Prospective Formation A and Prospective Formation B are separated by approximately 200 km. Prospective Formation A and Prospective Formation B include shale formations that are considered to be oil shales rich in organic matter.

<p dir="rtl">5 It also includes sand formations as potential gaseous hydrocarbon-bearing formations. Potential Formation A is a condensate and gas discovery. Potential Formation B is a dry gas discovery dominated by methane.</p>

Example 2

Pyrolysis experiments are performed on multiple oil shales recovered from Prospective Formation A10 and Prospective Formation B. Kerogen concentrate is separated from the oil shales in each experiment in order to

Subjected to thermal decomposition. CO2 is produced during each thermal decomposition experiment of the kerogen concentrate and the resulting CO2 is collected. The carbon isotopic signature of the produced CO2 is determined using IRMS. The δ13C values ​​of the produced CO2 are measured to be around -30‰. The carbon isotopic signature of the produced CO2 confirms that the CO2 produced from the kerogen is of organic origin, i.e., the produced CO2 is

Organic carbon.

Example 3

Multiple gas samples are recovered by WFT or DST, or both, from different target zones in the selected wells of Prospective Formation A and Prospective Formation B. The CO2 content of each gas sample is determined using GC. Also, the carbon isotopic fingerprint of the CO2 is determined.

Carbon was separated from each gas sample using IRMS in combination with GC. The results are plotted in Figure 4.

Figure 4 is a graph 400 illustrating the geochemical parameters of CO2 recovered from multiple target zones in selected wells for the Prospective Formation A and Prospective Formation B.

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b According to the detection model limits. The horizontal axis represents the CO2 content of the gas sample in molar percentage (mol%). The vertical axis represents the δ13C value of the CO2 separated from the gas sample in molar percentage (‰). The following regions are shown in Figure 4: Region 410 represents inorganic CO2; Region 420 represents organic CO2; and Region 430 represents the co-existence of inorganic CO2 and organic CO2. The following areas are shown in Figure 4: Area 440 includes gas samples recovered from the target areas of the potential formation A; Area 450 includes gas samples recovered from the areas

Targeted for the potential formation B; and area 460 includes gas samples recovered from some of the target areas of the potential formation B, which correspond to rich spots with a gas flow rate greater than 10 of about 283,168 standard cubic meters/day. The following points are illustrated in Figure 4: Points

The empty circles 460 represent gas samples recovered from target areas containing shale A; the black filled circles 462 represent gas samples recovered from target areas containing sand A; the square dots 464 represent gas samples recovered from target areas containing sand B; the triangular dots 466 represent gas samples recovered from areas

<p dir="rtl">15 Target areas containing clay B; cross-shaped points 468 represent gas samples recovered from target areas containing sand C; and inverted triangle points 470 represent gas samples recovered from target areas containing sand D. Clay A and Clay B are different types of clay where the symbols "A" and "B" are arbitrarily assigned and are intended only to distinguish between two types of clay. Sand A, Sand B, Sand C, and Sand D</p>

<p dir="rtl">20 They are different types of sand where the symbols "A", "B", "C", and "D" are assigned arbitrarily and are intended only to distinguish between four types of sand. As also shown in Figure 4, the slope curve 480 represents the dissolution of carbonates in impervious formations.</p>

The results shown in Figure 4 show that most of the gas samples recovered from the target areas in Prospective Formation A and Prospective Formation B contain inorganic CO2. As

<p dir="rtl">25 As shown in Figure 4, gas samples have a carbon dioxide content ranging from 0% to</p>

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%14 and the δ13C value ranges from -16‰ to 4‰. Most of the data points in area 440 corresponding to gas samples recovered from target areas in potential formation A fall into area 410 or area 430, indicating the presence of inorganic CO2. Most of the data points in area 450 corresponding to gas samples recovered from target areas in potential formation 5 B fall into area 410 or area 430, indicating the presence of CO2.

Inorganic. The data points are located in area 460 in area 410, which is an indication of the presence of inorganic CO2 and an indication of the presence of rich spots.

Example 4

A noble gas study was performed on the eight gas samples recovered from one or more of the 10 target areas in the potential formation B. Helium isotopic fingerprints are obtained for each gas sample.

Using IRMS to determine the value of R/Ra as shown for example in Equation (4):

R/Ra = (3He/4He)sample /(3He/4He)air

)4(

Where R is the ratio of 3He to 4He in the sample and Ra is the ratio of 3He to 4He in the present day 15 atmosphere. An R/Ra value greater than about 2.0 is an indication of carbon dioxide originating from

Magma or from the thermal decomposition of carbonates by magmatic intrusion. An R/Ra value ranging from about 1.0 to about 2.0 is indicative of CO2 originating from the mantle-crustal transition zone. An R/Ra value less than about 1.0 is indicative of CO2 originating from crustal origin, e.g. from melting of carbonates.

<p dir="rtl">20 The R/Ra values ​​obtained from the eight gas samples, ranging from about 0.02 to about 0.045, confirm that the inorganic CO2 identified in the gas samples did not originate from mantle degassing or volcanic activity.</p>

Example 5

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A petrographic analysis was performed on four samples recovered from multiple locations of the selected well for the potential formation B. DST was performed to measure the gas flow rate of the selected well, which is greater than about 283,168 scf/d. The results are shown in Figures 5a-h.

Figures 5A-H are photographs illustrating the petrographic analyses of the four recovered samples.

<p dir="rtl">5 From the selected well in the potential formation B according to the detection model limit. Figure 5a shows the petrographic analysis of a sandstone sample (Sample A with a porosity of 2.4% and a permeability of less than 0.01 mD) recovered from a site in a non-producing zone. Figure 5b shows the petrographic analysis of a sandstone sample (Sample B with a porosity of 7.6% and a permeability of 0.3 mD) recovered from a site in a non-producing zone near the interface between the non-producing zone and the producing zone.</p>

<p dir="rtl">10 Figure 5c shows the petrographic analysis of the sandstone sample (Sample C has a porosity of 17.1%).</p>

and a permeability of 785 mD) recovered from one site in the producing area. Figure 5d shows the petrographic analysis of a sandstone sample (Sample D has a porosity of 24.3% and a permeability of 2.182 mD) recovered from another site in the producing area. Figures 5e-g are magnified images of the selected areas shown in Figures 5a-d, respectively. As shown in Figures 5a-h, the symbol Oo represents

<p dir="rtl">15 Oval clay, FC represents siderite cement, CC represents calcite cement, I represents illite cement, QO represents quartz overgrowth, and P1 represents a large-sized preserved intergranular pore. The dark ring curves in Figures 5b-5d and 5f-5h indicate representative locations of intergranular pores. The thick arrows in Figure 5e show representative locations of filamentous intergranular contacts. The thick arrows in Figure 5f show representative etching locations of siderite cement</p>

<p dir="rtl">20 (FC). The bold arrows in Figure 5h indicate representative boundary locations for quartz growth.</p>

Quartz overgrowth (QO) through abundant clayey granular clastic layers.

The results of the rock characterization analysis shown in Figures 5A-H confirm that inorganic CO2 was formed from the dissolution of carbonate-based cement in the impermeable formations, which increased the formation pressure and improved the reservoir quality. As shown in Figures 5A-H, carbonate cementation was observed most frequently in sample A, followed by sample B, followed by sample C, and followed by sample D. On

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In contrast, preserved intergranular pores of large size (corresponding to P1) were observed more frequently in sample D, followed by sample C, followed by sample B, followed by sample A. These intergranular pores are formed by intrinsic carbonate dissolution. For example, Figure 5f shows possible etching of siderite (FC) near a large intergranular pore (P1), indicated by the thick arrow 5. Etching corresponding to carbonate dissolution of siderite increases porosity. Upon dissolution,

Inorganic carbon dioxide is produced and can be trapped in the intergranular pores.

Example 6

Multiple gas samples are recovered by DST from different target zones in selected wells of Prospective Formation A and Prospective Formation B. The CO2 content of each sample is determined.

<p dir="rtl">10 Gas using GC. Also, gas flow rate and WHFP are measured by DST in selected wells of potential formation A and potential formation B. The results are shown in Figure 6.</p>

Figure 6 is a graph 600 showing some geochemical parameters of CO2 recovered from multiple target areas in selected wells for Prospective Formation A and Prospective Formation B and some well productivity parameters for selected wells for Prospective Formation A and Prospective Formation B according to

<p dir="rtl">15 Detection model limits. The horizontal axis represents the CO2 content of the gas sample in mol%. The vertical axis represents the DST gas flow rate of the selected well in million standard cubic meters/day. The following areas are shown in Figure 6: Area 610 includes gas samples recovered from target areas of potential formation A and DST gas flow rates for potential formation A; Area 620 includes gas samples recovered from target areas of potential formation B and DST gas flow rates</p>

<p dir="rtl">20 DST for Prospective Formation B; Area 630 includes gas samples recovered from Prospective Formation B target areas and DST gas flow rates for Prospective Formation B, which correspond to rich spots with gas flow rates greater than 283,168 scf/d. Numerical symbols near the filled circles represent WHFP values ​​in megapascals (MPa).</p>

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The results show that potential formation A is not productive. The results also show that every data point corresponding to a hydrocarbon-rich spot (i.e., every data point with a gas flow rate greater than 283,168 scf/d) has a CO2 content greater than about 9%. The results also show a positive correlation between CO2 content and gas flow rate. Accordingly, in some models,

<p dir="rtl">5 The minimum value of the CO2 cut-off range can be set at about 9%.</p>

Example 7

The CO2 cutoff range specified in Example 6 was tested in a blind test type on different target zones in selected wells of the potential formation B. The results are shown in Table 1. The CO2 content was determined by WFT or DST, or both. As shown in Table 10, the DST examples provided only gas flow rate data. Some DST examples included CO2 flow rate data measured after undergoing a well stimulation process such as hydraulic fracturing. The predictions were based on a CO2 cutoff range greater than about 9%. Actual conclusions were determined in advance using traditional formation evaluation methods such as wireline well performance analysis.

Table 1

<tr><td><p dir="rtl">Actual conclusion</p></td><td><p dir="rtl">Predicting the presence of a rich spot based on the cutoff range</p><p>CO2</p></td><td><p dir="rtl">Gas flow rate after fracturing (standard cubic meters/day)</p></td><td><p dir="rtl">Gas flow rate (standard cubic meters/day)</p></td><td><p dir="rtl">How to take</p><p dir="rtl">Samples</p></td><td><p dir="rtl">content</p><p>CO2</p><p dir="rtl">)mall%(</p></td><td><p dir="rtl">type</p><p dir="rtl">The treasurer</p></td><td><p dir="rtl">The well</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>226534</p></td><td><p>DST</p></td><td><p>5.91</p></td><td><p dir="rtl">Sand A</p></td><td><p>J3</p></td></tr>

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<tr><td><p dir="rtl">project</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>226534</p></td><td><p>DST</p></td><td><p>5.97</p></td><td><p dir="rtl">Sand A</p></td><td><p>J3</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>226534</p></td><td><p>DST</p></td><td><p>6.01</p></td><td><p dir="rtl">Sand A</p></td><td><p>J3</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>226534</p></td><td><p>DST</p></td><td><p>5.99</p></td><td><p dir="rtl">Sand A</p></td><td><p>J3</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>226534</p></td><td><p>DST</p></td><td><p>5.97</p></td><td><p dir="rtl">Sand A</p></td><td><p>J3</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>226534</p></td><td><p>DST</p></td><td><p>6.01</p></td><td><p dir="rtl">Sand A</p></td><td><p>J3</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td><p>311485</p></td><td><p>DST</p></td><td><p>9.34</p></td><td><p dir="rtl">Sand A</p></td><td><p>S2</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td><p>311485</p></td><td><p>DST</p></td><td><p>9.34</p></td><td><p dir="rtl">Sand A</p></td><td><p>S2</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td><p>566336</p></td><td><p>104772</p></td><td><p>DST</p></td><td><p>9.29</p></td><td><p dir="rtl">Sand A</p></td><td><p>S3</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td><p>566336</p></td><td><p>104772</p></td><td><p>DST</p></td><td><p>9.32</p></td><td><p dir="rtl">Sand A</p></td><td><p>S3</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td><p>566336</p></td><td><p>104772</p></td><td><p>DST</p></td><td><p>9.18</p></td><td><p dir="rtl">Sand A</p></td><td><p>S3</p></td></tr><tr><td><p dir="rtl">unproductive</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>127425</p></td><td><p>DST</p></td><td><p>7.3</p></td><td><p dir="rtl">Sand C</p></td><td><p>S3</p></td></tr><tr><td><p dir="rtl">unproductive</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>127425</p></td><td><p>DST</p></td><td><p>7.23</p></td><td><p dir="rtl">Sand C</p></td><td><p>S3</p></td></tr><tr><td><p dir="rtl">unproductive</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>127425</p></td><td><p>DST</p></td><td><p>7.67</p></td><td><p dir="rtl">Sand C</p></td><td><p>S3</p></td></tr><tr><td><p dir="rtl">unproductive</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>127425</p></td><td><p>DST</p></td><td><p>7.67</p></td><td><p dir="rtl">Sand C</p></td><td><p>S3</p></td></tr><tr><td><p dir="rtl">unproductive</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>127425</p></td><td><p>DST</p></td><td><p>6.9</p></td><td><p dir="rtl">sand</p><p dir="rtl">for</p></td><td><p>S3</p></td></tr><tr><td><p dir="rtl">unproductive</p></td><td><p dir="rtl">unproductive</p></td><td></td><td><p>127425</p></td><td><p>DST</p></td><td><p>6.82</p></td><td><p dir="rtl">sand</p><p dir="rtl">for</p></td><td><p>S3</p></td></tr><tr><td><p dir="rtl">unproductive</p></td><td><p dir="rtl">unproductive</p></td><td><p>56633</p></td><td><p>14158</p></td><td><p>DST</p></td><td><p>8.85</p></td><td><p dir="rtl">Sand A</p></td><td><p>S4</p></td></tr>

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<tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td><p>283168&gt;</p></td><td><p>DST</p></td><td><p>10.03</p></td><td><p dir="rtl">Sand A</p></td><td><p>U3</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>9.36</p></td><td><p dir="rtl">Sand A</p></td><td><p>J1</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>9.4</p></td><td><p dir="rtl">Sand A</p></td><td><p>J1</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>10.26</p></td><td><p dir="rtl">Sand A</p></td><td><p>J2</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>9.64</p></td><td><p dir="rtl">Sand A</p></td><td><p>U1</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">unproductive</p></td><td></td><td></td><td><p>WFT</p></td><td><p>8.58</p></td><td><p dir="rtl">Sand A</p></td><td><p>U1</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>11.25</p></td><td><p dir="rtl">Sand A</p></td><td><p>U2</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>10.84</p></td><td><p dir="rtl">Sand A</p></td><td><p>U2</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>11.33</p></td><td><p dir="rtl">Sand A</p></td><td><p>S1</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>11.33</p></td><td><p dir="rtl">Sand A</p></td><td><p>S1</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>11.52</p></td><td><p dir="rtl">Sand A</p></td><td><p>S1</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>11.47</p></td><td><p dir="rtl">Sand A</p></td><td><p>S1</p></td></tr><tr><td><p dir="rtl">unproductive</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>9.08</p></td><td><p dir="rtl">Sand A</p></td><td><p>S5</p></td></tr><tr><td><p dir="rtl">unproductive</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>9.02</p></td><td><p dir="rtl">Sand A</p></td><td><p>S5</p></td></tr><tr><td><p dir="rtl">project</p></td><td><p dir="rtl">project</p></td><td></td><td></td><td><p>WFT</p></td><td><p>12.4</p></td><td><p dir="rtl">sand</p><p dir="rtl">Bg</p></td><td><p>S5</p></td></tr><tr><td><p dir="rtl">unproductive</p></td><td><p dir="rtl">unproductive</p></td><td></td><td></td><td><p>WFT</p></td><td><p>8.25</p></td><td><p dir="rtl">Sand A</p></td><td><p>U3</p></td></tr>

Table 1: Blind test results for CO2 cutoff range in different target areas

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The results in Table 1 indicate that the rich spot projections depend on the CO2 cutoff range and the actual conclusions in the general agreement. As shown in Table 1, DST target areas with CO2 content greater than about 9% were projected and identified as productive (i.e., gas flow rate greater than about 283,168 scf/d), both with and without

<p dir="rtl">5 Well stimulation. DST target zones with CO2 content less than about 9% were predicted and identified as non-producing (i.e., gas flow rate less than about 283,168 scf/d). WFT target zones with CO2 content greater than about 9% were predicted and identified as productive. WFT target zones with CO2 content less than about 9% were predicted and identified as non-producing.</p>

<p dir="rtl">10 Other modifications and alternative embodiments of various aspects of the disclosure will become apparent to those skilled in the art in the light of this description. Accordingly, this description should be construed as illustrative only and for the purpose of instructing those skilled in the art in the general method of carrying out the embodiments described in this disclosure. It is to be understood that the forms shown and described in the disclosure are to be taken as examples of embodiments. Elements and materials may be substituted for elements and materials shown and described in the disclosure, and parts and processes may be reversed or</p>

<p dir="rtl">15 Delete them, and certain features may be used independently, as will all be apparent to a person skilled in the art after making use of this description. Changes may be made to the items described in the disclosure without deviating from the spirit and scope of the disclosure as described in the following safeguards. The headings used and described in this disclosure are for regulatory purposes only and are not intended to</p>

Use it to limit the scope of this description.

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