Formation fluid sampling tool and use method thereof

Abstract

A downhole tool is configured to be located in a wellbore through a formation to obtain a formation fluid sample. In some embodiments, a downhole tool may include one or more fluid inlet ports configured to receive a formation fluid and a fluid monitor that may be configured to measure one or more formation fluid properties of the received formation fluid. At least one of the one or more fluid inlet ports may be in an open position. The one or more fluid inlet ports may be in an open position for a first time period (t) such that the one or more fluid inlet ports are configured to obtain formation fluid located within the formation at a first distance from the sidewall of the wellbore.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims priority to U.S. Provisional Patent Application No. 63 / 484,348, filed on February 10, 2023, which is incorporated herein by reference. Technical Field

[0003] The described embodiments generally relate to downhole tools for sampling formation fluids and methods of using the same. More specifically, the embodiments relate to predicting the arrival time (t) of fluids recovered from a given radius of a subsurface formation via a numerical flow model. Background Art

[0004] During drilling operations related to oil and gas (OG) and carbon capture and storage (CCS), as the wellbore is drilled, formation fluids within the formation undergo changes in their physical and / or chemical properties due to interactions with other exogenous or induced substances. Induced substances may be introduced through drilling mud invasion, drill bit deterioration, injection of formation testers, and other causes. These substances interact with the connate fluid through diffusion, miscibility, chemical reactions, and other methods, causing the properties of the formation fluid to vary with distance from the wellbore. Current formation fluid sampling techniques are limited to sampling the formation fluid closest to the wellbore, thus limiting the amount of information available for successful oil and gas drilling operations.

[0005] Therefore, there is a need for improved downhole formation fluid sampling tools and methods of using the same that can sample formation fluid at one or more predetermined distances from a wellbore. Summary of the Invention

[0006] A downhole tool is provided that is configured to be positioned in a wellbore extending through a formation to obtain a formation fluid sample located within the formation at a predetermined distance from a sidewall of the wellbore. In some embodiments, the downhole tool may include one or more fluid inlet ports configured to receive formation fluid and a fluid monitor configured to measure one or more formation fluid properties of the received formation fluid. At least one of the one or more fluid inlet ports may be in an open position. The one or more fluid inlet ports may be in the open position for a first time period (t) such that the one or more fluid inlet ports are configured to obtain formation fluid located within the formation at a first distance from the sidewall of the wellbore.

[0007] In other embodiments, a method for analyzing formation fluid is provided. The method for analyzing formation fluid may include positioning a downhole tool within a wellbore extending through a formation, the downhole tool comprising one or more fluid inlet ports and a fluid monitor; obtaining formation fluid via the one or more fluid inlet ports; and analyzing the formation fluid via the fluid monitor. The formation fluid may be obtained over a first time period (t) such that the formation fluid is obtained from the formation at a first distance from a sidewall of the wellbore. The fluid monitor may be configured to measure formation fluid properties of the formation fluid entering the downhole tool.

[0008] In other embodiments, a downhole tool is provided that is configured to be located in a wellbore passing through a formation to obtain a formation fluid sample located within the formation at a predetermined distance from the sidewall of the wellbore. In some embodiments, the downhole tool may include one or more fluid ports configured to receive formation fluid from the formation and a fluid monitor that can be configured to measure one or more formation fluid properties of the received formation fluid. The one or more fluid ports can be remotely configured to an open position or a closed position. The one or more fluid ports can be remotely configured to be in an open position within a first time period (t) such that the one or more fluid ports can be configured to obtain formation fluid located within the formation at a first distance from the sidewall of the wellbore.

[0009] In other embodiments, a downhole tool is provided that is configured to be positioned in a wellbore extending through a subterranean formation to inject a fluid into the subterranean formation at a predetermined distance from a sidewall of the wellbore. In some embodiments, the downhole tool may include one or more fluid ports capable of injecting the fluid into the subterranean formation. The one or more fluid ports may be remotely configured to an open position or a closed position.

[0010] In other embodiments, a method for obtaining formation fluid is provided. In some embodiments, the method may include positioning a downhole tool within a wellbore passing through a formation; obtaining formation fluid via at least one of one or more fluid ports; and analyzing the formation fluid via a fluid monitor. The downhole tool may include one or more fluid ports and a fluid monitor that can be remotely configured between an open position and a closed position. Formation fluid can be obtained within a first time period (t) such that formation fluid is obtained from the formation at a first distance from the sidewall of the wellbore. The fluid monitor can be configured to measure formation fluid properties of the formation fluid entering the downhole tool.

[0011] In other embodiments, a method for unstuck a downhole tool is provided. In some embodiments, the method may include determining that a downhole tool within a wellbore passing through a formation is stuck on the side of the wellbore, and performing a circulation operation at one or more remotely configurable fluid ports. The downhole tool may include one or more remotely configurable fluid ports. The circulation operation may include: remotely configuring a first remotely configurable fluid port to an open position; remotely configuring the remaining one or more remotely configurable fluid ports to a closed position; injecting fluid from the first remotely configurable fluid port in the open position for a certain duration; remotely configuring the first remotely configurable fluid port to a closed position; repeating the aforementioned steps for the first remotely configurable fluid port or subsequent remotely configurable fluid ports until the downhole tool is no longer stuck. BRIEF DESCRIPTION OF THE DRAWINGS

[0012] In order that the manner in which the above-described features of the present invention may be understood in detail, a more particular description of the invention, briefly summarized above, may be obtained by reference to embodiments, some of which are illustrated in the accompanying drawings. It should be noted, however, that the drawings illustrate only typical embodiments of the invention and, therefore, should not be considered limiting of its scope, as the invention may admit to other equally effective embodiments. It should be emphasized that the drawings are not necessarily drawn to scale, and that certain features and certain views of the drawings may be shown exaggerated in scale or in schematic form for the sake of clarity and / or brevity.

[0013] Figure 1 Depicted are graphical representations of formation fluid surrounding a sidewall of a wellbore including compositional variations along a distance extending from the sidewall of the wellbore into the formation according to one or more embodiments described.

[0014] Figure 2 Depicted are simplified schematic diagrams of four illustrative fluid access port arrangements that a downhole tool may include according to one or more embodiments described.

[0015] Figure 3 Depicts Figure 2 A tabular representation of the properties of the four fluid entry port arrangements of the downhole tool schematically shown in FIG.

[0016] Figure 4 Depicted is a simulation model of formation fluid being drawn over time toward two access ports of a downhole tool positioned 180° apart from each other, according to one or more embodiments described.

[0017] Figure 5 Described according to one or more embodiments, by Figure 2 shown in and Figure 3 Graphical representation of fractional flow over time resulting from the four fluid entry port arrangements described in .

[0018] Figure 6 Depicted are schematic and photographic representations of downhole tools and fluid access ports according to one or more embodiments described.

[0019] Figure 7 A schematic diagram of an active port selection map is depicted in accordance with one or more embodiments described.

[0020] Figure 8 Depicted is a schematic diagram of an active port selection diagram and fluid inlet port arrangement with multiple valves opening and closing according to one or more embodiments described.

[0021] Figure 9 A simplified schematic diagram of an illustrative fluid port arrangement for managing a tight formation using two open fluid ports is shown, according to one or more embodiments described.

[0022] Figure 10 Depicted is a simplified schematic diagram of an illustrative fluid port arrangement for targeted radial sampling utilizing one fluid port according to one or more embodiments described.

[0023] Figure 11 Depicted is a simplified schematic diagram of an illustrative fluid port arrangement for managing inefficient or detrimental formation conditions, according to one or more embodiments described.

[0024] Figure 12 Depicted is a simplified schematic diagram of an illustrative fluid port arrangement for managing a stuck downhole tool according to one or more embodiments described.

[0025] Figure 13 Depicted is a simplified schematic diagram of an exemplary active port arrangement for measuring azimuthal mobility of a downhole tool according to one or more embodiments described. DETAILED DESCRIPTION

[0026] It should be understood that the following disclosure describes several exemplary embodiments for implementing different features, structures or functions of the present invention. Exemplary embodiments of components, arrangements and configurations are described below to simplify the present disclosure; however, these exemplary embodiments are provided as examples only and are not intended to limit the scope of the present invention. In addition, the present disclosure may repeat reference numbers and / or letters in the various embodiments and figures provided herein. This repetition is for the purpose of simplicity and clarity and does not substantially determine the relationship between the various embodiments and / or configurations. In addition, the exemplary embodiments set forth below may be combined in any combination, that is, any element in one exemplary embodiment may be used in any other exemplary embodiment without departing from the scope of the present disclosure.

[0027] In addition, certain terms are used in the following description and claims to refer to specific components. Those skilled in the art will understand that various entities may refer to the same component by different names, and therefore, the naming conventions of the elements described herein are not intended to limit the scope of the present invention unless otherwise expressly defined herein. In addition, the naming conventions used herein are not intended to distinguish components that have different names but the same function.

[0028] As used herein, language of degree, such as the terms "approximately," "about," "substantially," and "substantially" as used herein, refers to a value, amount, or characteristic that is close to a stated value, amount, or characteristic that still performs a desired function or achieves a desired result. For example, the terms "approximately," "about," "substantially," and "substantially" may refer to an amount that differs by less than 10%, less than 5%, less than 1%, less than 0.1%, and / or less than 0.01% from the stated amount. As another example, in certain embodiments, the terms "substantially parallel" and "substantially parallel" or "substantially perpendicular" and "substantially perpendicular" refer to a value, amount, or characteristic that differs by less than or equal to 15 degrees, 10 degrees, 5 degrees, 3 degrees, 1 degree, or 0.1 degrees from being perfectly parallel or perpendicular, respectively.

[0029] Furthermore, in the following discussion and in the claims, the terms "including" and "comprising" are used in an open-ended fashion, and thus should be interpreted to mean "including, but not limited to."

[0030] The term "or" is intended to cover both the exclusive and inclusive cases, ie, "A or B" is intended to be synonymous with "at least one of A and B," unless the context clearly dictates otherwise.

[0031] The indefinite articles "a" and "an" refer to both the singular (i.e., "one") and the plural (i.e., one or more) unless the context clearly dictates otherwise. For example, embodiments using "an olefin" include embodiments using one, two, or more olefins unless specified otherwise or the context clearly dictates that only one olefin is used.

[0032] Unless otherwise indicated herein, all numerical values ​​are "about" or "approximately" the indicated values, which means that these values ​​take into account experimental errors, machine tolerances, and other variations that would be expected by a person of ordinary skill in the art. It should also be understood that the precise numerical values ​​used in the specification and claims constitute specific embodiments. Every effort has been made to ensure the accuracy of the data in the examples. However, it should be understood that any measured data inherently contains a certain degree of error due to limitations of the technology and / or equipment used for measurement.

[0033] Each of the appended claims defines a separate invention, which for infringement purposes is considered to include equivalents to the various elements or limitations specified in the claims. Depending on the context, all references to the "invention" may in some cases refer only to certain specific embodiments. In other cases, it will be recognized that references to the "invention" will refer to the subject matter described in one or more (but not necessarily all) of the claims. Each invention is described in more detail below, including specific embodiments, versions, and examples, but the invention is not limited to these embodiments, versions, or examples, which, when the information in this disclosure is combined with publicly available information and technology, enable a person of ordinary skill in the art to make and use the invention.

[0034] Figure 1 A graphical representation of a formation fluid composition gradient around a sidewall 111 of a wellbore 120 is depicted, including compositional changes along a distance extending from the sidewall 111 of the wellbore 120 into the formation 100, according to one or more embodiments. In some embodiments, the wellbore 120 may be used to produce oil and / or natural gas. In other embodiments, the wellbore 120 may be used for carbon capture and storage. In some embodiments, a downhole tool may be configured to obtain formation fluid around the wellbore 111 located within the formation 100 at one or more distances, or "target radii," away from the center of the wellbore 120. Figure 1 As depicted, formation fluid located at target radii 101 and / or 102 and / or 103 can be determined and obtained from within formation 100 and outside wellbore 120 relative to the center of wellbore 120 within formation 100. In some embodiments, multiple radii 101, 102, 103 can be measured from the center of wellbore 120, or from any other suitable location within wellbore 120 that can be used to determine a location within formation 100 and outside wellbore 120 that enters formation 100.

[0035] One or more target radii 101, 102, and 103 can be configured to focus on one or more specific regions within the formation 100 surrounding the wellbore 120, respectively. A specific region of the formation 100 can be described or referred to as an area or range located between or outside the radial boundaries of the sidewall 111, invasion radius 112, and / or maximum invasion radius 113. The invasion radius 112 can be the distance from the center of the wellbore 120 into the formation 100 that extends to a given distance into the formation 100 and can include a non-formation fluid region 130. The non-formation fluid region 130 between the sidewall 111 and the invasion radius 112 can contain no or little formation fluid. The maximum invasion radius 113 can be the distance from the center of the wellbore 120 into the formation 100 that extends to a given distance into the formation 100 and can include an invaded fluid region 140 located between the maximum invasion radius 113 and the non-formation fluid region 130. The invaded fluid region 140 between the invasion radius 112 and the maximum invasion radius 113 may contain a mixture of non-formation fluid and formation fluid. The maximum invasion radius 113 may be the maximum distance from the center of the wellbore 120 at which diffusion and / or miscibility processes between the non-formation fluid and the formation fluid may occur. Beyond the maximum invasion radius 113 may be an unaltered fluid region 150. The unaltered fluid region 150 may contain unaltered formation fluid. In some embodiments, the target radius 101 may be located within the invaded fluid region 140. In some embodiments, the target radius 102 may be located at or near the maximum invasion radius 113. In some embodiments, the target radius 103 may be located within the unaltered fluid region 150.

[0036] Figure 2A simplified schematic diagram of four different fluid entry port arrangements 210, 220, 230, 240 that may be included in a downhole tool according to one or more embodiments is depicted. The fluid entry port arrangements 210, 220, 230, 240 may be any entry port arrangement suitable for receiving a fluid (non-formation fluid, formation fluid, or a mixture or reaction product thereof) located outside the wellbore 120. In some embodiments, the fluid entry port arrangement 210 may include a single port, such as described in U.S. Patent No. 11,280,191 B2 and / or U.S. Patent No. 8,453,732 B2. In some embodiments, the fluid entry port arrangement 220 may include four entry ports, such as described in U.S. Patent Application Publication No. 2021 / 0293122 A1, which may be located around the downhole tool with equal spacing between each port. In some embodiments, the third fluid entry port arrangement 230 can include two entry ports, as described in U.S. Patent Application Publication No. 2021 / 0293122A1, which can be located around the downhole tool with equal spacing between each port. In some embodiments, the fourth fluid entry port arrangement 240 can include a single port, as described in U.S. Patent Application Publication No. 2021 / 0293122A1. In some embodiments, the fluid entry port arrangement can be selected based at least in part on the need for formation fluid testing prior to using the downhole tool. The fluid entry port arrangements 210, 220, 230, 240 can include a fluid monitor 250. The fluid monitor 250 can include any measuring device, gauge, flow meter, sensor, and / or the like, or any combination thereof, capable of recording, tracking, measuring, detecting, transmitting, or any combination thereof, the flow of fluid into, through, and / or around the fluid entry port arrangements 210, 220, 230, 240. The fluid monitor 250 may also analyze one or more properties of the fluid, such as composition, temperature, pressure, viscosity, and / or any other desired property.

[0037] Figure 3A tabular representation of the properties of four fluid entry port arrangements 210, 220, 230, 240 of a downhole tool according to one or more embodiments is depicted. The fluid entry port arrangements 210, 220, 230, and 240 can be shown as having port arrangement properties 310, 320, 330, and 340, respectively. The properties 310, 320, 330, 340 of the four fluid entry port arrangements 210, 220, 230, 240 can include a sample area, a protection area, and a total area. The sample area can be configured to receive non-formation fluids, native formation fluids, and / or mixtures thereof for testing and / or monitoring. The protection area can be configured to reduce or even prevent materials that may contaminate, inhibit, and / or hinder testing and / or monitoring from entering the sample area. The total area can include the sum of the sample area and the protection area. In some embodiments, the protection area can be larger than the sample area to reduce or even prevent materials that may contaminate, inhibit, and / or hinder testing and / or monitoring from entering the sample area.

[0038] Figure 4 Depicted is a simulation model of formation fluid being drawn over time toward two fluid entry ports of a downhole tool that are 180° apart from each other, according to one or more embodiments. Figure 4 As depicted, formation fluid may be pumped toward a downhole tool in a series of states 310 , 320 , 330 over time. Figure 4 Each of the series of states 310, 320, and 330 depicted in FIG. 1 shows the positions of both non-formation fluid and formation fluid over time as the downhole tool draws fluid from the formation 100 into the wellbore 120 and into the downhole tool. In the first state 310, the non-formation fluid and formation fluid may be in their original positions before the downhole tool began operating. In some embodiments, the maximum invasion radius 113 may be 90 inches from the outer edge of the sidewall 111. In the second state 320, the downhole tool may be in operation for a period of time, wherein the non-formation fluid and formation fluid may no longer be in their original positions but have not yet been drawn into the downhole tool. The maximum invasion radius 113 may move closer to the downhole tool in the second state 320. As the downhole tool draws formation fluid toward itself, the maximum invasion radius 113 may begin to expand to a certain distance, forming a transition zone 305. In the third state 330, the downhole tool may be in operation for a period of time, wherein the transition zone 305 has been drawn into the downhole tool. In a third state 330, a more detailed view 335 of the transition zone 305 drawn into the downhole tool can be seen.

[0039] Figure 5 Depicted is a method for Figure 2 shown in and Figure 3Graphs of the flow fractions generated over time by the four fluid entry port arrangements described in [5]. In each of the four performance tests 510, 520, 530, and 540, the performance of the four fluid entry port arrangements 210, 220, 230, and 240 can be represented as a graph of the flow fraction, measured as the percentage of fluid drawn into the downhole tool from a set radial distance versus time, measured in hours. The horizontal dashed line can represent a 1% fluid fraction threshold, which can be understood as the approximate time at which the downhole tool receives fluid from the specified distance. The four performance tests 510, 520, 530, and 540 illustrate the performance of the four fluid entry port arrangements 210, 220, 230, and 240 at depths greater than 60 inches, greater than 90 inches, greater than 120 inches, and greater than 150 inches, respectively. In some embodiments, fluid entry port arrangement 240 can reach the 1% fluid fraction threshold faster than the other fluid entry port arrangements.

[0040] In some embodiments, the downhole tool may include a fluid monitor to analyze the fluid being drawn into the downhole tool. In some embodiments, the fluid monitor may be used to analyze or otherwise estimate any number of properties of the fluid being drawn into the downhole tool. In some embodiments, one or more properties that may be analyzed or otherwise estimated via the fluid monitor may be or may include, but are not limited to, fluid type, chemical composition (e.g., hydrocarbon component fraction), viscosity, gas-to-oil ratio, mass density, optical density, formation volume factor, resistivity, fluorescence, American Petroleum Institute (API) gravity, phase properties (such as saturation pressure, bubble point, pour point, and stability of asphaltene), etc., or any combination thereof.

[0041] The fluid monitor can determine the percentage of fluid drawn into the downhole tool from within a predetermined radius by using a numerical flow model. In some embodiments, the numerical flow model can be a predictive model utilizing one or more Navier-Stokes equations or similarly applicable partial differential equations, or any combination thereof. In some embodiments, the model inputs can include wellbore diameter, initial formation pressure, formation thickness, formation porosity, formation permeability, formation fluid density, formation fluid viscosity, formation fluid compressibility, tool inlet geometry, tool pumping rate, and / or any other suitable boundary conditions or variables required to simulate the formation 100 and wellbore 120. In some embodiments, the fluid monitor can use the numerical flow model to predict the time required for a selected fluid entry port arrangement to draw fluid from a selected radius. The fluid monitor can be used to determine the location source of the sampled non-formation fluid and formation fluid.

[0042] In some embodiments, the numerical flow model can predict the arrival time (t) of fluid from a given radius R in the formation 100. The arrival time (t) can be the time it takes for the formation fluid originating from the given radius R to reach the downhole tool. The numerical flow model can include two coupled partial differential equations describing the flow of the formation fluid and the flow of the tracer. The tracer can be calculated as a massless component of the numerical flow model to distinguish between formation fluid closer to the sidewall 111 of the wellbore 120 than the given radius R and formation fluid farther from the sidewall 111 of the wellbore 120 than the given radius R.

[0043] In some embodiments, the numerical flow model can generate an output. The output can include fluid pressure and tracer concentration as a function of time and spatial position in the formation 100. The arrival time (t) can be determined by solving two coupled partial differential equations. In some embodiments, the arrival time (t) can be when the volume fraction of the formation fluid obtained by the downhole tool from a given radius R or greater is greater than 1%. The arrival time (t) of each fluid entry port configuration can be determined to determine which fluid entry port configuration can result in the shortest arrival time (t). In some embodiments, the given radius R can be changed to determine the change in arrival time (t) as a function of depth within the formation 100.

[0044] Figure 6Schematic diagrams and photographic representations of downhole tools and fluid access ports according to one or more embodiments are depicted. The downhole tool 600 can be any suitable tool having one or more fluid access ports 610 that can draw in or receive formation fluid from the surrounding wellbore 120. In one or more embodiments, the downhole tool can be as described in U.S. Patent No. 11,441,422 B2, U.S. Patent No. 11,280,191 B2, U.S. Patent No. 8,453,732 B2, U.S. Patent No. 4,860,581 A, U.S. Patent No. 4,936,139 A, U.S. Patent No. 6,719,049 B2, U.S. Patent No. 6,964,301 B2, and / or U.S. Patent Application Publication No. 2021 / 0293122 A1. One or more fluid inlet ports 610 can be configured to be in an open position or a closed position, such that when in the open position, the fluid inlet port can receive formation fluid, while when in the closed position, the fluid inlet port is prevented from receiving formation fluid. One or more fluid inlet ports 610 can be placed in a closed position by positioning a connecting rod 601, a plug 602, an external O-ring 603, and a sampling ring 604 between the fluid inlet port 610 and the sampling line 605. In some embodiments, the combination of the plug 602, the external O-ring 603, and the sampling ring 604 can be replaced by any suitable component or combination of components sufficient to configure the fluid inlet port 610 in the closed position. In one or more embodiments, the open / closed configuration of the downhole tool 600 can be configured or arranged at the surface by manually configuring each port before the downhole tool 600 is deployed in the wellbore 120.

[0045] In some embodiments, when the downhole tool includes two or more fluid inlet ports, the number of open fluid inlet ports can be limited to less than the total number of fluid inlet ports. In some embodiments, the number of open fluid inlet ports can be limited to only four, only three, only two, or only one fluid inlet port. The configuration of the open and closed fluid inlet ports can be used to change the amount of fluid that the downhole tool 600 draws from the area surrounding the wellbore 120 per unit time. In one or more embodiments, the downhole tool 600 can be configured to draw formation fluid located within the formation 100 at a predetermined distance from the sidewall 111 of the wellbore 120. In some embodiments, the predetermined distance can be about 15 inches, about 25 inches, about 40 inches, about 50 inches, about 60 inches, about 90 inches, about 120 inches, about 150 inches, or more from the sidewall 111 of the wellbore 120.

[0046] In some embodiments, the downhole tool 600 may include one or more storage compartments 620 configured to hold one or more reagents. When the tool is at the surface and before the tool is located in the wellbore 120, the one or more reagents may be placed in one or more of the storage compartments 620. In some embodiments, the at least one reagent contained in at least one storage compartment 620 may be injected into the formation 100 at a given depth in the wellbore 120 via the downhole tool 600. In some embodiments, the downhole tool 600 may be configured to receive the one or more reagents from the surface after the downhole tool 600 is located in the wellbore 120. In some embodiments, the downhole tool 600 may be configured to inject the at least one reagent received from the surface into the formation 100 at a given depth in the wellbore 120 after the downhole tool 600 has been located in the wellbore 120.

[0047] One or more reagents can include any reagent suitable for formation testing, formation fluid testing, cleaning in or around the wellbore 120 and / or formation, processing in or around the wellbore 120 and / or formation, etc. or any combination thereof. In some embodiments, the reagent can be non-reactive or can react with one or more elements or compounds located in the formation 100. In some embodiments, the reagent can be a gas, liquid, solid or multiphase composition. In some embodiments, the reagent can be a surfactant or other chemical substance. In some embodiments, the reagent can be or can include one or more chemical substances, conductive materials, charged materials, magnetic materials, reactive materials, metallic materials or otherwise detectable materials or substances. In some embodiments, the reagent can serve as or be used as a tracer material.

[0048] In some embodiments, the reagent can be an acidic compound or a basic compound. In some embodiments, the reagent can be or can include, but is not limited to; potassium; sodium; lithium; magnesium; calcium; bromide; iodide; one or more complex salts, such as nitrate, thiocyanate, fluorobenzoic acid or hydrogen borate; an isotopically enriched fluid, such as deuterated water or tritiated water; a fluid containing a colorimetric or fluorescent dye, such as a rhodamine dye, a cyanine dye and / or a fluorescein dye; nitrogen; carbon dioxide; sulfur hexafluoride; freons; deuterated hydrocarbons; noble gases, such as helium and / or argon; perfluorocarbons, such as perfluorodimethylcyclobutane (PDMCB), perfluoromethylcyclopentane (PMCP), perfluoromethylcyclohexane (PMCH), 1,2- and 1,3-perfluorodimethylcyclohexane (1,2- / 1,3-PDMCH); one or more alcohols, such as methanol, ethanol and / or propanol; one or more hydrocarbons, such as propane, propylene, butylene, butane and / or pentane; a polymer; any combination thereof; or any mixture thereof.

[0049] In some embodiments, the tracer may be calculated as a massless component of the numerical flow model and may be a reagent that is intentionally injected into the wellbore 120 and / or formation 100 via the downhole tool 600. In other embodiments, the tracer that may be calculated as a massless component of the numerical flow model may be one or more materials or compounds that are introduced into the wellbore 120 and / or formation 100 during drilling of the wellbore 120. For example, the tracer may be drilling mud or other material that is introduced into the wellbore 120 and / or formation 100 during drilling of the wellbore 120. In still other embodiments, the tracer may be a combination of one or more reagents that are intentionally injected into the wellbore 120 and / or formation via the downhole tool 600 and one or more other materials that are introduced into the wellbore 120 and / or formation 100 during drilling of the wellbore 120.

[0050] In some embodiments, the downhole tool 600 can include one or more fluid injection ports capable of injecting a reagent into or around the wellbore 120 and / or into the formation 100. In some embodiments, the one or more fluid entry ports 610 can be configured to also function as one or more fluid injection ports, wherein the one or more ports function as fluid entry ports when pumping operations draw formation fluid toward the downhole tool 600, and the one or more ports function as fluid injection ports when pumping operations inject a reagent into and / or around the wellbore 120 and / or the formation. In some embodiments, the downhole tool 600 can be configured with one or more fluid injection ports that are separate and isolated from the one or more fluid entry ports 610. Thus, when a decision is made to implement the injection of a reagent into and / or around the wellbore 120 and / or formation 100, the fluid entry port 610 and / or one or more fluid injection ports separate and isolated from the fluid entry port 610 can be configured to receive the reagent from one or more storage compartments 620 located within the downhole tool 600 and / or from a drilling location located at the surface.

[0051] In some embodiments, the downhole tool 600 can be used to collect fluid samples from increasing distances from the wellbore 120. The fluid samples are of interest because they can be used to study the incremental effects of changing physical and / or chemical properties of formation fluids. In some embodiments, the output generated by the numerical flow model can be used to determine at least one of a field development plan for a subsurface formation and / or a production plan for the subsurface formation. At least one of the field development plan for the subsurface formation and / or the production plan for the subsurface formation can include at least one study and / or evaluation. In some embodiments, the at least one study and / or evaluation can include: a study of the effects of mud filtrate on the chemical and / or physical composition of the formation and / or formation fluids, an evaluation of drilling-induced hydrogen sulfide profiles, surfactants and other non-formation fluids, a study of the effects of mud filtrate on asphaltene precipitation pressure, an evaluation of induced diffusion processes, a quality control study of drilling mud filtrate fluid loss properties, an evaluation of base oil emulsion stability, an evaluation of formation mineral phase change profiles, and / or any combination thereof.

[0052] Figure 7 A schematic diagram of an active port selection diagram 700 is depicted according to one or more embodiments. The active port selection diagram 700 can include a plurality of fluid ports 701, 702, 703, 704 of a downhole tool, a first fluid flow line 710, and a second fluid flow line 720. The plurality of fluid ports 701, 702, 703, 704 can include any suitable fluid entry ports that can be remotely configured to a closed or open position. The first fluid flow line 710 and the second fluid flow line 720 can include any suitable means for delivering fluids to and / or from the plurality of fluid ports 701, 702, 703, 704, the fluids including, but not limited to, injection fluids, sampled fluids, formation fluids, other downhole fluids (e.g., drilling fluids), and / or any combination thereof. In one or more embodiments, the plurality of fluid ports 701, 702, 703, 704 can be remotely configured to a closed position or an open position from a surface location. In one or more embodiments, the plurality of fluid ports 701, 702, 703, 704 can be remotely configured to a closed position or an open position while the downhole tool is located within the wellbore. In one or more embodiments, the plurality of fluid ports 701, 702, 703, 704 can be configured to inject or withdraw fluid or passively allow fluid to flow through the active ports in the open position.

[0053] Figure 8A schematic diagram of an active port selection diagram and fluid intake port arrangement 800 with multiple valves that open and close, according to one or more embodiments, is depicted. The active port selection diagram and fluid intake port arrangement 800 with multiple valves that open and close, according to one or more embodiments, can include a plurality of fluid ports 701, 702, 703, 704, a first fluid flow line 710 and a second fluid flow line 720 of a downhole tool, and a wellbore 830 including a forced fluid flow 840. The forced fluid flow 840 can include any fluid flow caused or resulting from the injection and / or intake of fluid into or around the plurality of fluid ports 701, 702, 703, 704. In one or more embodiments, the plurality of fluid ports 701, 702, 703, 704 can be independently configured to be in an open position or a closed position to direct the forced fluid flow 840 through, into, out of, and / or around the wellbore 830, or any combination thereof.

[0054] In one or more embodiments, the plurality of fluid ports 701, 702, 703, 704 can be remotely configured from the surface to generate a user-defined and / or desired forced fluid flow 840. Remote configuration can include any method of sending signals to remote actuators, valves, and / or other mechanical devices that can open and close the plurality of fluid ports 701, 702, 703, 704 individually, independently, and / or simultaneously. Sending electronic signals can include wired communication and / or wireless communication. In one or more embodiments, the plurality of fluid ports 701, 702, 703, 704 can be configured to an open or closed position by a controller or other automated device located on or around the downhole tool. The controller or other automated device can be configured to receive one or more instructions sent by a user, either wired or wirelessly, to configure the plurality of fluid ports 701, 702, 703, 704 to a range of open or closed positions based on the one or more instructions. In one or more embodiments, the user can select forced fluid flow 840 in response to conditions in, on, or around the wellbore 830.

[0055] Figure 9A simplified schematic diagram of an illustrative active port arrangement 900 for managing tight formations using two open fluid ports, according to one or more embodiments, is shown. The simplified schematic diagram of the illustrative active port arrangement 900 may include a formation map 910 having a sample area, a protection area, and a total area, as well as a time-pressure map 920. A tight formation may be any type of formation having conditions, such as porosity, density, viscosity, or any combination thereof, that make it difficult for fluids to flow through the formation. Difficulties in fluid movement may include, but are not limited to, exceeding pump limits, exceeding the phase envelope of the formation fluid, or any combination thereof. The sample area may be configured to receive non-formation fluids, native formation fluids, and / or mixtures thereof for testing and / or monitoring. The protection area may be configured to reduce or even prevent materials that may contaminate, inhibit, and / or interfere with testing and / or monitoring from entering the sample area. The total area may include the sum of the sample area and the protection area. In some embodiments, the protection area may be larger than the sample area to reduce or even prevent materials that may contaminate, inhibit, and / or interfere with testing and / or monitoring from entering the sample area.

[0056] The time-pressure graph 920 may include a first pressure drop 921 and a second pressure drop 922. The first pressure drop 921 and the second pressure drop 922 depict the difference between the total formation open flow area. A larger pressure drop (the second pressure drop 922 compared to the first pressure drop 921) may be an indication that the formation open flow area is smaller or smaller. A smaller pressure drop (the first pressure drop 921 compared to the second pressure drop 922) may be an indication that the formation open flow area is larger or larger. A smaller formation open flow area may occur when only one fluid port is used to draw in formation fluid, the formation has a dense formation section, or any other condition that reduces the formation open flow area, or any combination thereof. A larger formation open flow area may occur when two or more fluid ports are used to draw in formation fluid, the formation has a porous or permeable formation section, or any other condition that increases the formation open flow area, or any combination thereof. In one or more embodiments, dense formations can be managed by configuring two fluid ports to an open position and two fluid ports to a closed position to draw in fluid from opposite sides of the downhole tool. In some embodiments, during formation testing using a single fluid port, a given depth may be deemed "untestable" due to low permeability (excessive pressure drop). In such embodiments, one or more additional fluid ports can be remotely configured to an open position to increase the area available for fluid flow until the pressure drop is manageable without consuming additional time to retract and reposition the downhole tool to another location within the wellbore.

[0057] Figure 10A simplified schematic diagram of an illustrative active port arrangement 1000 for targeted radial sampling utilizing one active fluid port and three inactive fluid ports is depicted, according to one or more embodiments. The active port arrangement 1000 for targeted radial sampling utilizing one active port can include a formation map 1010 having a sampling area, a protection area, and a total area. In one or more embodiments, targeted radial sampling can be managed by configuring one fluid port to an open position 1020 and three fluid ports to a closed position 1030 to draw fluid from a single direction within the formation relative to the downhole tool. In such an embodiment, the open fluid port 1020 can be directed toward an area of ​​the formation with minimal resistance to fluid flow, thereby enabling fluid sampling at a faster rate. In other embodiments, the closed fluid port 1030 can be directed toward an area of ​​the formation with greater resistance to fluid flow, thereby preventing wasted fluid sampling effort in areas of lower formation permeability.

[0058] Figure 11 A simplified schematic diagram of an exemplary active port arrangement 1100 for managing ineffective or deleterious formation conditions using two active ports 1120 and two inactive fluid ports 1130, according to one or more embodiments, is depicted. The active port arrangement 1100 may include a formation map 1110 having a total area, a tight formation section, and a wrinkled formation section. The ineffective or deleterious formation conditions may include tight formation sections or wrinkled formation sections. The wrinkled formation sections may include any formation characteristics, including grooves, roughness, pitting, etc., or any combination thereof, that prevent the area surrounding the ports from sealing when in contact with the formation. In one or more embodiments, wrinkled formations can be managed by configuring two fluid ports in an open position 1120 and two fluid ports in a closed position 1130. The fluid ports in the closed position 1130 may contact the formation closest to the tight and wrinkled formation sections, respectively. The fluid ports in the open position 1120 may contact the formation in an area or regions distal to the tight and wrinkled formation sections, respectively. In one or more embodiments, the active port arrangement can be remotely configured to an open and / or closed position to avoid wrinkles and / or tight formation sections without moving the downhole tool.

[0059] Figure 12A simplified schematic diagram of an illustrative active port arrangement 1200 for managing a stuck downhole tool 1230 is depicted, according to one or more embodiments. The active port arrangement 1200 can include a stratigraphic map 1210 having a total area, an active port 1220, a stuck downhole tool 1230, an open fluid port 1240, and one or more closed fluid ports 1250. A stuck downhole tool 1230 can include any downhole tool condition, wherein the downhole tool 1230 has a blocked and / or clogged active port, the downhole tool 1230 is stuck and / or stuck to the side of a wellbore, or any combination thereof. The active port 1220 can include any active port configured to change from a closed position to an open position and back to a closed position to force, for example, a fluid ejection. In one or more embodiments, the active port 1220 can be quickly selected and / or alternated between the open position 1240 and the closed position 1250. Such an operation may be referred to as selectively "blowing" or "cycling" the active port 1220 to remove material that is blocking the port and / or to push the downhole tool 1230 away from the wall of the wellbore. In one or more embodiments, a stuck downhole tool 1230 may be managed by cycling the active port 1220 between active and inactive states to dislodge the downhole tool from the side of the wellbore and / or clear any blockage or obstruction in one or more fluid ports.

[0060] Figure 13A simplified schematic diagram of an exemplary active port arrangement 1300 for measuring azimuthal mobility of a downhole tool, according to one or more embodiments, is depicted. Active port arrangement 1300 may include a stratigraphic map 1310 having a total area and directions along one or more axes, and at least one remote sensor 1320. Measuring azimuthal mobility may include determining the movement of the downhole tool before, during, and / or after fluid is drawn and / or injected through the active port arrangement. The at least one remote sensor 1320 may include any sensor capable of detecting motion along or about one or more linear axes, including but not limited to accelerometers, gyroscopes, geophones, seismometers, or any combination thereof. In one or more embodiments, the azimuthal mobility of the downhole tool may be tracked or measured using remote sensor 1320, which may detect linear movement along one or more of the x, y, and / or z axes and / or rotational movement about one or more of the x, y, and / or z axes, and / or any combination thereof. In some embodiments, measuring azimuthal mobility may provide real-time fluid movement data to surface users for future downhole operation planning and / or operation optimization. In some embodiments, measuring azimuthal mobility can determine the orientation of fluid ports within a well. In some embodiments, understanding the orientation of the fluid ports and the intake and / or injection of fluids through one or more fluid ports can provide information about the preferred direction of fluid flow. This information can be used to perform downhole operations, such as for geosteering and / or guiding well placement.

[0061] All patents and patent applications, test procedures (such as ASTM methods, UL methods, etc.), and other documents cited herein are fully incorporated by reference to the extent such disclosure is not inconsistent with this disclosure and for all jurisdictions where such incorporation is permitted.

[0062] Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be understood that, unless otherwise indicated, ranges include any combination of two values, for example, any lower value combined with any higher value, any two lower values ​​combined, and / or any two higher values ​​combined. Certain lower limits, upper limits, and ranges appear in one or more of the claims that follow.

[0063] The features of several embodiments have been listed above so that those skilled in the art can

[0064] The present disclosure can be better understood. Those skilled in the art will appreciate that they can easily

[0065] The present disclosure is used to design or modify a device for implementing the same purpose and / or achieving the same purpose as disclosed herein

[0066] The same advantages of the embodiments of the present invention are based on other methods or devices.

[0067] It should also be realized that such equivalent constructions do not depart from the spirit and scope of the disclosure, and their

[0068] Various changes, substitutions, and modifications may be made herein without departing from the spirit and scope of the present disclosure.

[0069] The present invention is susceptible to variations and modifications, and its scope may be determined by the appended claims.

Claims

1. A downhole tool configured to be positioned in a wellbore penetrating a subterranean formation to obtain a formation fluid sample located within the subterranean formation at a predetermined distance from a sidewall of the wellbore, the downhole tool comprising: one or more fluid ports configured to receive formation fluid, wherein at least one of the one or more fluid ports is configured in an open position; as well as A fluid monitor configured to measure one or more formation fluid properties of a received formation fluid, wherein the one or more fluid ports are configured to be in an open state during a first time period (t) such that the one or more fluid ports are configured to obtain formation fluid located within the formation at a first distance from the sidewall of the wellbore.

2. A downhole tool according to claim 1, wherein the one or more fluid ports are configured to remain open for a second time period (t+Δt1), so that the one or more fluid ports are configured to obtain formation fluid located in the formation at a second distance from the sidewall of the wellbore.

3. A downhole tool according to claim 2, wherein the one or more fluid ports are configured to remain open for a third time period (t+Δt1+Δt2), so that the one or more fluid ports are configured to obtain formation fluid located in the formation at a third distance from the sidewall of the wellbore.

4. The downhole tool of any one of claims 1 to 3, wherein at least one of the one or more fluid ports is further configured to inject one or more reagents into the wellbore and / or the formation.

5. A downhole tool according to claim 4, wherein at least one of the one or more fluid ports configured to inject the one or more reagents into the wellbore and / or the formation is configured to receive the one or more reagents from a drilling location located on the ground and / or from one or more storage compartments located within the downhole tool.

6. The downhole tool of any one of claims 1 to 3, wherein the one or more fluid ports are further configured to inject one or more reagents into the wellbore and / or the formation.

7. The downhole tool of claim 6, wherein the one or more fluid injection ports are configured to receive the one or more reagents from a wellbore location at the surface and / or from one or more storage compartments within the downhole tool.

8. A method for obtaining formation fluid, comprising: positioning a downhole tool within a wellbore penetrating the formation, the downhole tool comprising a fluid monitor and one or more fluid ports; obtaining a formation fluid via the one or more fluid ports, wherein the formation fluid is obtained over a first period of time (t) such that the formation fluid is obtained from the formation at a first distance from the sidewall of the wellbore; as well as The formation fluid is analyzed via the fluid monitor, wherein the fluid monitor is configured to measure formation fluid properties of the formation fluid entering the downhole tool.

9. The method of claim 8, wherein the formation fluid is obtained within a second time period (t+Δt1) such that the formation fluid is obtained from the formation at a second distance from the sidewall of the wellbore.

10. The method of claim 9, wherein the formation fluid is obtained within a third time period (t+Δt1+Δt2) such that the formation fluid is obtained from the formation at a third distance from the sidewall of the wellbore.

11. The method of any one of claims 8 to 10, wherein the formation fluid is analyzed using a numerical flow model.

12. The method of claim 11, wherein the numerical flow model utilizes the Navier-Stokes equations to predict and simulate the flow of the formation fluid through the formation from a predetermined distance from the sidewall of the wellbore over a predetermined time period.

13. A method according to claim 11 or claim 12, wherein the numerical flow model includes multiple input variables, and the multiple input variables include wellbore diameter, initial formation pressure, formation thickness, formation porosity, formation permeability, formation fluid density, formation fluid viscosity, formation fluid compressibility, fluid port geometry and downhole tool pumping rate.

14. A method according to any one of claims 11 to 13, wherein the numerical flow model includes two coupled partial differential equations, and the two coupled partial differential equations describe the flow of formation fluid and the flow of tracer to distinguish between formation fluid closer to the wellbore than a predetermined distance and formation fluid farther from the wellbore than the predetermined distance.

15. The method of claim 14, wherein the tracer is calculated as a massless component of the numerical flow model.

16. The method of any one of claims 11 to 15, wherein the output generated by the numerical flow model can be used to determine a field development plan for a subsurface formation and / or a production plan for a subsurface formation.

17. The method of any one of claims 8 to 16, further comprising injecting one or more reagents into the wellbore and / or the formation via at least one of the one or more fluid ports prior to obtaining the formation fluid.

18. A method according to any one of claims 8 to 16, wherein the one or more fluid ports are further configured to inject one or more reagents into the wellbore and / or the formation, and the method further comprises injecting one or more reagents into the wellbore and / or the formation via the one or more fluid ports before obtaining the formation fluid.

19. A downhole tool configured to be positioned in a wellbore penetrating a subterranean formation to obtain a formation fluid sample located within the subterranean formation at a predetermined distance from a sidewall of the wellbore, the downhole tool comprising: one or more fluid ports configured to receive formation fluid from the formation, wherein the one or more fluid ports are remotely configurable to an open position or a closed position; as well as A fluid monitor configured to measure one or more formation fluid properties of a received formation fluid, wherein at least one of the one or more fluid ports is remotely configurable to be in the open position for a first time period (t) such that the at least one of the one or more fluid ports is configured to obtain formation fluid located within the formation at a first distance from the sidewall of the wellbore.

20. A downhole tool according to claim 19, wherein at least one of the one or more fluid ports is remotely configured to remain in the open position for a second time period (t+Δt1), so that at least one of the one or more fluid ports is configured to obtain formation fluid located in the formation at a second distance from the sidewall of the wellbore.

21. A downhole tool according to claim 20, wherein at least one of the one or more fluid ports is remotely configured to remain in the open position for a third time period (t+Δt1+Δt2), so that at least one of the one or more fluid ports is configured to obtain formation fluid located in the formation at a third distance from the sidewall of the wellbore.

22. A downhole tool according to claim 19, wherein the downhole tool includes at least two of the fluid ports, and wherein at least one of the at least two fluid ports can be remotely configured to be in the closed position to direct fluid to one or more of the fluid ports maintained in the open position.

23. A downhole tool configured to be positioned in a wellbore penetrating a subterranean formation to inject a fluid into the subterranean formation at a predetermined distance from a sidewall of the wellbore, the downhole tool comprising: One or more fluid ports configured to inject fluid into the formation, wherein the one or more fluid ports are remotely configurable to an open position or a closed position.

24. A downhole tool according to claim 23, wherein the downhole tool further comprises one or more fluid ports configured to receive formation fluid from the formation, wherein the one or more fluid ports configured to receive the formation fluid can be remotely configured to an open position or a closed position.

25. A downhole tool according to claim 24, wherein the downhole tool includes two or more of the fluid ports configured to receive the formation fluid from the formation, and wherein at least one of the two or more fluid ports is capable of being remotely configured to the closed position to direct the fluid to the fluid port configured to receive the formation fluid maintained in the open position.

26. A method for obtaining formation fluid, comprising: positioning a downhole tool within a wellbore penetrating the earth's formation, the downhole tool comprising a fluid detector and one or more fluid ports remotely configurable between an open position and a closed position; obtaining a formation fluid via at least one of the one or more fluid ports, wherein the formation fluid is obtained over a first period of time (t) such that the formation fluid is obtained from the formation at a first distance from the sidewall of the wellbore; as well as The formation fluid is analyzed via the fluid monitor, wherein the fluid monitor is configured to measure formation fluid properties of the formation fluid entering the downhole tool.

27. The method of claim 26, further comprising remotely configuring at least one of the one or more fluid ports to an open position or a closed position based on user preference.

28. The method of claim 27, wherein the user preferences include at least one of a tight formation avoidance operation, a wrinkled formation avoidance operation, and an azimuthal mobility test operation.

29. The method of claim 28, wherein the user preferences include the tight formation avoidance operation, and wherein the tight formation avoidance operation includes remotely configuring one or more fluid ports proximate to the tight formation to a closed position.

30. The method of claim 28, wherein the user preferences include the wrinkled formation avoidance operation, and wherein the wrinkled formation avoidance operation includes remotely configuring one or more fluid ports proximate a wrinkled formation to a closed position.

31. A method according to claim 28, wherein the user preferences include the azimuthal fluidity testing operation, and wherein the azimuthal fluidity testing operation includes remotely configuring one or more of the fluid ports to a user-selected open position and a closed position to determine the azimuthal fluidity of the downhole tool in and around the wellbore and / or the formation.

32. The method of claim 31 , further comprising detecting changes in or about an x, y, or z axis using one or more remote sensors configured to detect linear and rotational motion in or about an x, y, or z axis.

33. A method for unstuck a downhole tool, comprising: determining that a downhole tool within a wellbore extending through the earth's formation is stuck on a side of the wellbore, the downhole tool including one or more fluid ports remotely configurable between an open position and a closed position; as well as performing a cycling operation on at least one of the one or more fluid ports, wherein the cycling operation comprises: remotely configuring at least one of the one or more fluid ports to the open position; injecting fluid from said at least one of said one or more fluid ports in said open position for a duration; remotely configuring the at least one of the one or more fluid ports to the closed position; and The foregoing steps are repeated for the at least one of the one or more fluid ports until the downhole tool is no longer stuck.

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