FORMATION FLUID SAMPLING TOOLS AND PROCESSES FOR USING SAME

Abstract

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

Description

CROSS REFERENCE TO RELATED APPLICATION

This application claims priority to U.S. Provisional Patent Application No. 63/484,348, filed on Feb. 10, 2023, which is incorporated by reference herein.

FIELD

Embodiments described generally relate to downhole tools for formation fluid sampling and processes for using same. More particularly, such embodiments relate to predicting an arrival time (t) of fluid recovered from a subterranean formation from a given radius within the subterranean formation via a numerical flow model.

BACKGROUND

During Oil & Gas (OG) and Carbon Capture & Storage (CCS) related drilling operations, as a wellbore is drilled, the formation fluid within the formation can undergo changes in its physical and/or chemical characteristics due to interaction with other exogenous or induced substances. Induced substances can be introduced as a result of drilling mud invasion, drilling bit metamorphism, injection from formation testers, and the like. The interaction of these substances with the native fluids through diffusion, miscibility, chemical reaction(s), and the like can result in the formation fluid having properties that vary with distance from the wellbore. Current formation fluid sampling techniques are limited to only sampling the formation fluid nearest the wellbore, limiting the amount of information available for successful oil and gas drilling operations.

There is a need, therefore, for improved downhole formation fluid sampling tools and processes for using same that can sample formation fluid at one or more predetermined distances away from the wellbore.

SUMMARY

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

In other embodiments, a process for analyzing a formation fluid is provided. The process for analyzing a formation fluid can include locating a downhole tool within a wellbore traversing a formation, the downhole tool comprising one or more fluid intake ports and a fluid monitor, obtaining a formation fluid via the one or more fluid intake ports, and analyzing the formation fluid via the fluid monitor. The formation fluid can be obtained for 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. The fluid monitor can be configured to measure formation fluid properties of the formation fluid entering the downhole tool.

In other embodiments, a downhole tool configured to be located in a wellbore traversing a formation to obtain a formation fluid sample located at a predetermined distance within the formation from a sidewall of the wellbore is provided. In some embodiments, the downhole tool can include one or more fluid ports configured to receive a 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 configurable to an open position or a closed position. The one or more fluid ports can be remotely configured to be in the open position for a first period of time (t) such that the one or more fluid ports can be configured to obtain formation fluid located at a first distance from the sidewall of the wellbore within the formation.

In other embodiments, a downhole tool configured to be located in a wellbore traversing a formation to inject a fluid to a predetermined distance within the formation from a sidewall of the wellbore is provided. In some embodiments, the downhole tool can include one or more fluid ports that can inject a fluid into the formation. The one or more fluid ports can be remotely configurable to an open position or a closed position.

In other embodiments, a process for obtaining a formation fluid is provided. In some embodiments, the process can include locating a downhole tool within a wellbore traversing a formation, obtaining a formation fluid via at least one of the one or more fluid ports, and analyzing the formation fluid via the fluid monitor. The downhole tool can include one or more fluid ports remotely configurable between an open position and a closed position and a fluid monitor. The formation fluid can be obtained for 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. The fluid monitor can be configured to measure formation fluid properties of the formation fluid entering the downhole tool.

In other embodiments, a process for unsticking a downhole tool is provided. In some embodiments, the process can include determining a downhole tool within a wellbore traversing a formation is stuck to the side of the wellbore and performing a cycling operation at the one or more remotely configurable fluid ports. The downhole tool can include one or more remotely configurable fluid ports. The cycling operation can 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 time duration, remotely configuring the first remotely configurable fluid port to a closed position, and repeating the prior steps on the first remotely configurable fluid port or a subsequent remotely configurable fluid port until the downhole tool is no longer stuck.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are, therefore, not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. It is emphasized that the figures are not necessarily to scale and certain features and certain views of the figures can be shown exaggerated in scale or in schematic for clarity and/or conciseness.

FIG. 1 depicts a graphical representation of a formation fluid surrounding a sidewall of a wellbore that includes a compositional change along a distance extending from the sidewall of the wellbore into a formation, according to one or more embodiments described.

FIG. 2 depicts simplified schematic representations of four illustrative fluid intake port arrangements a downhole tool can include, according to one or more embodiments described.

FIG. 3 depicts a tabular representation of properties of the four fluid intake port arrangements of the downhole tool schematically shown in FIG. 2.

FIG. 4 depicts a simulation model of formation fluid being pulled toward two intake ports located 180° apart from one another of a downhole tool over time, according to one or more embodiments described.

FIG. 5 depicts a graphical representation of a fraction of fluid produced through the four fluid intake port arrangements shown in FIG. 2 and described in FIG. 3 over time, according to one or more embodiments described.

FIG. 6 depicts a schematic and photographic representation of the downhole tool and fluid intake ports, according to one or more embodiments described.

FIG. 7 depicts a schematic representation of an active port selection diagram, according to one or more embodiments described.

FIG. 8 depicts a schematic representation of an active port selection diagram and fluid intake port arrangement with a plurality of open and closed valves, according to one or more embodiments described.

FIG. 9 depicts a simplified schematic representation of an illustrative fluid port arrangement for managing a tight formation with two open fluid ports, according to one or more embodiments described.

FIG. 10 depicts a simplified schematic representation of an illustrative fluid port arrangement for targeted radial sampling with one fluid port, according to one or more embodiments described.

FIG. 11 depicts a simplified schematic representation of an illustrative fluid port arrangement for managing ineffective or detrimental formation conditions, according to one or more embodiments described.

FIG. 12 depicts a simplified schematic representation of an illustrative fluid port arrangement for managing a stuck downhole tool, according to one or more embodiments described.

FIG. 13 depicts a simplified schematic representation of an illustrative active port arrangement for measuring azimuthal mobility of a downhole tool, according to one or more embodiments described.

DETAILED DESCRIPTION

It is to be understood that the following disclosure describes several exemplary embodiments for implementing different features, structures, or functions of the invention. Exemplary embodiments of components, arrangements, and configurations are described below to simplify the present disclosure; however, these exemplary embodiments are provided merely as examples and are not intended to limit the scope of the invention. Additionally, the present disclosure can repeat reference numerals and/or letters in the various embodiments and across the figures provided herein. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations. Moreover, the exemplary embodiments presented below can be combined in any combination of ways, i.e., any element from one exemplary embodiment can be used in any other exemplary embodiment, without departing from the scope of the disclosure.

Additionally, certain terms are used throughout the following description and claims to refer to particular components. As one skilled in the art will appreciate, various entities can refer to the same component by different names, and as such, the naming convention for the elements described herein is not intended to limit the scope of the invention, unless otherwise specifically defined herein. Further, the naming convention used herein is not intended to distinguish between components that differ in name but not function.

Language of degree used herein, such as the terms “approximately,” “about,” “generally,” and “substantially” as used herein represent a value, amount, or characteristic close to the stated value, amount, or characteristic that still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” “generally,” and “substantially” may refer to an amount that is within less than 10% of, within less than 5% of, within less than 1% of, within less than 0.1% of, and/or within less than 0.01% of the stated amount. As another example, in certain embodiments, the terms “generally parallel” and “substantially parallel” or “generally perpendicular” and “substantially perpendicular” refer to a value, amount, or characteristic that departs from exactly parallel or perpendicular, respectively, by less than or equal to 15 degrees, 10 degrees, 5 degrees, 3 degrees, 1 degree, or 0.1 degree.

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.”

The term “or” is intended to encompass both exclusive and inclusive cases, i.e., “A or B” is intended to be synonymous with “at least one of A and B,” unless otherwise expressly specified herein.

The indefinite articles “a” and “an” refer to both singular forms (i.e., “one”) and plural referents (i.e., one or more) unless the context clearly dictates otherwise. For example, embodiments using “an olefin” include embodiments where one, two, or more olefins are used, unless specified to the contrary or the context clearly indicates that only one olefin is used.

Unless otherwise indicated herein, all numerical values are “about” or “approximately” the indicated value, meaning the values take into account experimental error, machine tolerances and other variations that would be expected by a person having ordinary skill in the art. It should also be understood that the precise numerical values used in the specification and claims constitute specific embodiments. Efforts have 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 level of error due to the limitation of the technique and/or equipment used for making the measurement.

Each of the appended claims defines a separate invention, which for infringement purposes is recognized as including 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 to certain specific embodiments only. In other cases, it will be recognized that references to the “invention” will refer to subject matter recited in one or more, but not necessarily all, of the claims. Each of the inventions will now be described in greater detail below, including specific embodiments, versions, and examples, but the inventions are not limited to these embodiments, versions or examples, which are included to enable a person having ordinary skill in the art to make and use the inventions, when the information in this disclosure is combined with publicly available information and technology.

FIG. 1 depicts a graphical representation of a formation fluid composition gradient surrounding a sidewall 111 of a wellbore 120 that includes a compositional change along a distance extending from the sidewall 111 of the wellbore 120 into a formation 100, according to one or more embodiments. In some embodiments, the wellbore 120 can be for the production of oil and/or gas. In other embodiments, the wellbore 120 can be utilized for carbon capture and storage. In some embodiments, a downhole tool can be configured to obtain formation fluid surrounding the wellbore 111 at one or more distances or “target radiuses” located away from a center of the wellbore 120 within the formation 100. As depicted in FIG. 1, formation fluid located at a target radius 101 and/or 102 and/or 103 can be determined and obtained from within the formation 100 with respect to a center of the wellbore 120 within the formation 100 beyond the wellbore 120. In some embodiments, the plurality of radii 101, 102, 103 can be measured from a center of the wellbore 120 or from any other suitable location within the wellbore 120 that can be used to determine the location within the formation 100 beyond the wellbore 120 into the formation 100.

The one or more target radiuses 101, 102, 103 can be configured to focus on one or more specific regions, respectively, within the formation 100 surrounding the wellbore 120. The specific regions of the formation 100 can be described or referred to as the region or area between or beyond the radial boundary of the sidewall 111, an invasion radius 112, and/or a maximum invasion radius 113. The invasion radius 112 can be a distance from the center of the wellbore 120 into the formation 100 that extends 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 nearly no formation fluid. The maximum invasion radius 113 can be a distance from the center of the wellbore 120 into the formation 100 that extends a given distance into the formation 100 and can include an invasive fluid region 140 located between the maximum invasion radius 113 and the non-formation fluid region 130. The invasive fluid region 140 between the invasion radius 112 and the maximum invasion radius 113 can contain a mixture of non-formation fluids and formation fluids. The maximum invasion radius 113 can be the maximum distance from the center of the wellbore 120 at which diffusion and/or miscibility processes between non-formation fluids and formation fluids can occur. Beyond the maximum invasion radius 113 can include an unaltered fluid region 150. The unaltered fluid region 150 can contain unaltered formation fluid. In some embodiments, the target radius 101 can be located within the invasive fluid region 140. In some embodiments, the target radius 102 can be located at or close to the maximum invasion radius 113. In some embodiments, target radius 103 can be located within the unaltered fluid region 150.

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

FIG. 3 depicts a tabular representation of properties of the four fluid intake port arrangements 210, 220, 230, 240 of the downhole tool, according to one or more embodiments. The fluid intake port arrangements 210, 220, 230, and 240 can be shown to have the port arrangement properties 310, 320, 330, and 340, respectively. The properties 310, 320, 330, 340 of the four fluid intake port arrangements 210, 220, 230, 240 can include a sample area, a guard area, and a total area. The sample area can be configured to receive non-formation fluids, native formation fluids, and/or a mixture thereof for testing and/or monitoring. The guard area can be configured to reduce or even prevent materials from entering the sample area that may foul, inhibit, and/or hinder testing and/or monitoring. The total area can include the summation of the sample area and the guard area. In some embodiments, the guard area can be larger than the sample area in order to reduce or even prevent materials from entering the sample area that may foul, inhibit, and/or hinder testing and/or monitoring.

FIG. 4 depicts a simulation model of formation fluid being pulled toward two fluid intake ports located 180° apart from one another on a downhole tool over time, according to one or more embodiments. As depicted in FIG. 4, formation fluid can be drawn toward the downhole tool over time across a series of states 310, 320, 330. Each of the series of states 310, 320, 330 depicted in FIG. 4 show the location of both non-formation fluid(s) 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(s) and formation fluid can be in their original position before the downhole tool begins operation. In some embodiments, the maximum invasion radius 113 can be 90 inches from the outer edge of the sidewall 111. In the second state 320, the downhole tool can be in operation for a time where the non-formation fluids and formation fluids can be no longer in their original position but not yet drawn into the downhole tool. The maximum invasion radius 113 can be moved closer to the downhole tool in the second state 320. The maximum invasion radius 113 can begin to spread across a distance as the downhole tool draws formation fluids toward itself, forming a transitory zone 305. In the third state 330, the downhole tool can be in operation for a time where the transitory zone 305 has been drawn into the downhole tool. In the third state 330, a more detailed view 335 of the transitory zone 305 drawn into the downhole tool can be seen.

FIG. 5 depicts a graphical representation of a fraction of fluid produced for the four fluid intake port arrangements shown in FIG. 2 and described in FIG. 3 over time, according to one or more embodiments. In each of the four performance tests 510, 520, 530, 540, the performance of the four fluid intake port arrangements 210, 220, 230, 240 can be represented as a graph of fluid fraction measured as a percentage of fluid drawn into the downhole tool from a set radial distance vs time measured in hours. The horizontal dashed line can represent the fluid fraction threshold of 1%, which can be understood as the approximate moment the downhole tool received fluid from a specified distance. The four performance tests 510, 520, 530, 540 show the performance at greater than 60 inches, greater than 90 inches, greater than 120 inches, and greater than 150 inches, respectively, of the four fluid intake port arrangements 210, 220, 230, 240. In some embodiments, the fluid intake port arrangement 240 can reach the fluid fraction threshold of 1% more quickly than other fluid intake port arrangements.

In some embodiments, the downhole tool can include a fluid monitor to analyze the fluids drawn into the downhole tool. In some embodiments, the fluid monitor can be used to analyze or otherwise estimate any number of properties of the fluids drawn into the downhole tool. In some embodiments, the property or properties that can be analyzed or otherwise estimated via the fluid monitor can be or can include, but are not limited to fluid type, chemical composition (e.g., hydrocarbon component fractions), 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, bubblepoint, pour point, and stability of asphaltenes, and the like or any combination thereof.

The fluid monitor can determine the percentage of fluid drawn within the downhole tool from a predetermined radius through the use of a numerical flow model. In some embodiments, the numerical flow model can be a predictive model that utilizes one or more Navier-Stokes equations or similar applicable partial differential equations, or any combination thereof. In some embodiments, the model inputs can include a wellbore diameter, an initial formation pressure, a formation thickness, a formation porosity, a formation permeability, a formation fluid density, a formation fluid viscosity, a formation fluid compressibility, a tool inlet geometry, a tool pumping rate, and/or any other suitable boundary condition or variable necessary to model the formation 100 and wellbore 120. In some embodiments, the fluid monitor can use the numerical flow model to predict the time a selected fluid intake port arrangement can take to draw in fluid from a selected radius. The fluid monitor can be used to determine a location source for sampled non-formation fluids and formation fluids.

In some embodiments, the numerical flow model can predict an arrival time (t) of fluid from a given radius R in the formation 100. The arrival time (t) can be the time at which formation fluid, originating at the given radius R, arrives at the downhole tool. The numerical flow model can include two coupled partial differential equations describing the flow of formation fluid together with the flow of a tracer. The tracer can be computed as a mass-less 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 the formation fluid further away from the sidewall 111 of the wellbore 120 than the given radius R.

In some embodiments, the numerical flow model can produce 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 formation fluid originating at the given radius R or greater obtained by the downhole tool is greater than 1%. The arrival time (t) can be determined for each fluid intake port configuration to determine which fluid intake port configuration can lead to the shortest arrival time (t). In some embodiments, the given radius R can be varied to determine the variability of arrival time (t) as a function of depth within the formation 100.

FIG. 6 depicts a schematic and photographic representation of the downhole tool and fluid intake ports, according to one or more embodiments. The downhole tool 600 can be any suitable tool with one or more fluid intake ports 610 capable of drawing in or receiving formation fluid from around the wellbore 120. In one or more embodiments, the downhole tool can be as described in U.S. Pat. Nos. 11,441,422 B2, 11,280,191 B2, 8,453,732 B2, 4,860,581 A, 4,936,139 A, 6,719,049 B2, 6,964,301 B2, and/or U.S. Patent Application Publication No.2021/0293122 A1. The one or more fluid intake ports 610 can be configured to be in an open position or a closed position, such that when in the open position the fluid intake port can receive formation fluid and when in the closed position the fluid intake port can be prevented from receiving formation fluid. The one or more fluid intake ports 610 can be in the closed position by locating a connecting rod 601, a plug 602, an external O-ring 603, and a sampling ring 604 between the fluid intake port 610 and sampling line 605. In some embodiments, the combination of the plug 602, the external O-ring 603, and the sampling ring 604 can be substituted by any suitable component or combination of components sufficient to configure the fluid intake port 610 into the closed position. In one or more embodiments, the opened/closed configuration of the downhole tool 600 can be configured or arranged at the surface by manually configuring each port prior to deploying the downhole tool 600 into the wellbore 120.

In some embodiments, when the downhole tool includes two or more fluid intake ports, the number of open fluid intake ports can be limited to less than the total number of fluid intake ports. In some embodiments, the number of open fluid intake ports can be limited to only four, only three, only two, or only one fluid intake port(s). The configuration of the open position and closed position fluid intake ports can be used to change the amount of fluid per unit of time the downhole tool 600 can draw formation fluid from the area surrounding the wellbore 120. In one or more embodiments, the downhole tool 600 can be configured to draw formation fluid located at a predetermined distance within the formation 100 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 greater from the sidewall 111 of the wellbore 120.

In some embodiments, the downhole tool 600 can include one or more storage compartments 620 configured to contain one or more agents. The one or more agents can be placed into one or more of the storage compartment(s) 620 while the tool is located at the surface and prior to the tool being located within the wellbore 120. In some embodiments, at least one agent contained in at least one storage compartment 620 can be injected via the downhole tool 600 into the formation 100 at a given depth within the wellbore 120. In some embodiments, the downhole tool 600 can be configured to receive the one or more agents from the surface after the downhole tool 600 has been located within the wellbore 120. In some embodiments, the downhole tool 600 can be configured to inject at least one agent received form the surface after the downhole tool 600 has been located within the wellbore 120 into the formation 100 at a given depth within the wellbore 120.

The one or more agents can include any agent suitable for formation testing, formation fluid testing, cleaning in or around the wellbore 120 and/or formation, treatment in or around the wellbore 120 and/or formation, and/or the like, or any combination thereof. In some embodiments, the agent can be non-reactive or reactive with one or more elements or compounds located within the formation 100. In some embodiments, the agent can be a gas, a liquid, a solid, or a multi-phase composition. In some embodiments, the agent can be a surfactant or other chemical. In some embodiments, the agent can be or can include, one or more chemical species, electrically conductive materials, electrically charged materials, magnetic materials, reactive materials, metallic materials, or otherwise detectable material(s) or substance(s). In some embodiments, the agent can act or serve as a tracer material.

In some embodiments, the agent can be an acid compound or a base compound. In some embodiments, the agent can be or can include, but is not limited to; potassium; sodium; lithium; magnesium; calcium; a bromide; an iodides; one or more complex salts, e.g., a nitrate, a thiocyanate, a fluorobenzoic acid, or a hydrogen borate; enriched isotopic fluids e.g., deuterated or tritiated water; a fluid containing colorimetric or fluorescent dyes, e.g., a rhodamine dye, a cyanine dye, and/or a fluorescein dye; nitrogen; carbon dioxide; sulfur hexafluoride; a freon; a deuterated hydrocarbon; a noble gas, e.g., helium and/or argon; a perflurocarbon, e.g., perfluorodimethylcyclobutane (PDMCB), perfluoromethylcyclopentane (PMCP), perfluoromethylcyclohexane (PMCH), 1,2- and 1,3-perfluorodimethylcyclohexane (1,2-/1,3-PDMCH); one or more alcohols, e.g., methanol, ethanol, and/or propanol; one or more hydrocarbons, e.g., propane, propene, butene, butane, and/or pentane; a polymer; any combination thereof, or any mixture thereof.

In some embodiments, the tracer that can be computed as a mass-less component of the numerical flow model and can be the agent intentionally injected into the wellbore 120 and/or the formation 100 via the downhole tool 600. In other embodiments, the tracer that can be computed as a mass-less component of the numerical flow model can be one or more materials or compounds introduced into the wellbore 120 and/or the formation 100 during drilling of the wellbore 120. For example, the tracer can be drilling mud or other materials introduced into the wellbore 120 and/or the formation 100 during drilling of the wellbore 120. In still other embodiments, the tracer can be a combination of one or more agents intentionally injected into the wellbore 120 and/or the formation via the downhole tool 600 and one or more other materials introduced into the wellbore 120 and/or the formation 100 during drilling of the wellbore 120.

In some embodiments, the downhole tool 600 can include one or more fluid injection ports capable of injecting the agent(s) in or around the wellbore 120 and/or into the formation 100. In some embodiments, the one or more fluid intake ports 610 can be configured to also function as the one or more fluid injection ports, where the one or more ports function as fluid intake ports when pumping operations draw formation fluids toward the downhole tool 600 and the one or more ports function as fluid injection ports when pumping operations inject the agent(s) into and/or around the wellbore 120 and/or formation. In some embodiments, the downhole tool 600 can be configured to have one or more fluid injection ports that are separate and apart from the one or more fluid intake ports 610. As such, the fluid intake port(s) 610 and/or the one or more fluid injection ports separate and apart from the fluid intake port(s) 610 can be configured to receive the agent(s) from the one or more storage compartments 620 located within the downhole tool 600 and/or from a drilling site located at the surface when injection of the agent(s) into and/or around the wellbore 120 and/or the formation 100 is decided to be carried out.

In some embodiments, the downhole tool 600 can be used to collect fluid samples from increasing distances from the wellbore 120. The fluid samples can be of interest as they allow the study of incremental impact on physical and/or chemical properties of altered formation fluids. In some embodiments, the output produced by the numerical flow model can be used to determine at least one of a field development plan for the subsurface formation and/or a production plan for the subsurface formation. The at least one of a field development plan for the subsurface formation and/or 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 effect of mud filtrate on the chemical and/or physical composition of the formation and/or formation fluids, a drilling induced hydrogen sulfide profile, an evaluation of surfactants and other non-formation fluids, a study of impact of mud filtrate on asphaltene onset pressure, an evaluation of induced diffusion processes, a quality control study of drilling mud fluid loss properties, an evaluation of stability of base oil emulsions, an evaluation of a formation mineralogy alteration profile, and/or the like, and/or any combination thereof.

FIG. 7 depicts a schematic representation of an active port selection diagram 700, according to one or more embodiments. The active port selection diagram 700 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. The plurality of fluid ports 701, 702, 703, 704 can include any suitable fluid intake port that can be remotely configured into a closed or open position. The first fluid flow line 710 and the second fluid flow line 720 can include any suitable means of transporting fluids to and/or from the plurality of fluid ports 701, 702, 703, 704 that can include, but are not limited to, injection fluid, sampling fluid, formation fluids, other downhole fluids, e.g., drilling fluid, and/or any combinations thereof. In one or more embodiments, the plurality of fluid ports 701, 702, 703, 704 can be remotely configured into 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 into the closed position or the open position while the downhole tool is located within a wellbore. In one or more embodiments, the plurality of fluid ports 701, 702, 703, 704 can be configured to inject or draw in fluid or passively allow fluid to flow through an active port in the open position.

FIG. 8 depicts a schematic representation of an active port selection diagram and fluid intake port arrangement 800 with a plurality of open and closed valves, according to one or more embodiments. The active port selection diagram and fluid intake port arrangement 800 with a plurality of open and closed valves can include the plurality of fluid ports 701, 702, 703, 704, the first fluid flow line 710 and the second fluid flow line 720 of a downhole tool, and a wellbore 830 that includes a compelled fluid flow 840. The compelled fluid flow 840 can include any fluid flow induced or caused by the injection and/or intake of fluid in 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 independently be configured to be in an open position or a closed position to direct the compelled fluid flow 840 through, in, out, and/or around the wellbore 830, or any combinations thereof.

In one or more embodiments, the plurality of fluid ports 701, 702, 703, 704 can be remotely configured from the surface to produce a user-defined and/or desired compelled fluid flow 840. Remote configuration can include any method of sending signals to a distant actuator, valve, and/or other mechanical device capable of opening and closing the plurality of fluid ports 701, 702, 703, 704 individually, independently, and/or concurrently with one another. 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 into an open or closed position by a controller or other automatic device located on or about the downhole tool. The controller or other automatic device can be configured to receive one or more instructions from a user, sent wired or wirelessly, to configure the plurality of fluid ports 701, 702, 703, 704 into a series of open or closed positions based upon the one or more instructions. In one or more embodiments, the compelled fluid flow 840 can be selected by a user to respond to conditions in, on, or around the wellbore 830.

FIG. 9 depicts a simplified schematic representation of an illustrative active port arrangement 900 for managing a tight formation with two open fluid ports, according to one or more embodiments. The simplified schematic representation of the illustrative active port arrangement 900 can include a formation diagram 910 with a sample area, a guard area, and a total area, and a time-pressure graph 920. The tight formation can be any kind of formation with conditions such as porosity, density, viscosity, and the like, or any combination thereof, that makes it difficult for a fluid to flow through the formation. Difficulty to move the fluid can include, but not be limited to, exceeding pump limits, exceeding the phase envelope of the formation fluid, and the like, or any combination thereof. The sample area can be configured to receive non-formation fluids, native formation fluids, and/or a mixture thereof for testing and/or monitoring. The guard area can be configured to reduce or even prevent materials from entering the sample area that may foul, inhibit, and/or hinder testing and/or monitoring. The total area can include the summation of the sample area and the guard area. In some embodiments, the guard area can be larger than the sample area to reduce or even prevent materials from entering the sample area that may foul, inhibit, and/or hinder testing and/or monitoring.

The time-pressure graph 920 can include a first drawdown 921 and a second drawdown 922. The first and second drawdowns 921, 922 depict the differences between total formation area open to flow. A large drawdown (the second drawdown 922 as compared to the first drawdown 921) can be an indication of a smaller or less formation area open to flow. A small drawdown (the first drawdown 921 as compared to the second drawdown 922) can be an indication of a larger or greater formation area open to flow. Smaller formation areas open to flow can occur when only one fluid port is used to draw in formation fluids, the formation has a tight formation section, or any other condition that reduces the formation area open to flow, or any combination thereof. Larger formation areas open to flow can occur when two or more fluid ports are used to draw in formation fluids, the formation has a porous or permeable section, or any other condition that increases the formation area open to flow, or any combination thereof. In one or more embodiments, the tight formation can be managed by configuring two fluid ports into the open position and two fluid ports into the 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 as “non-testable” due to low permeability (excessive drawdown). In such embodiments, one or more additional fluid ports can be remotely configured into the open position to increase area available to fluid flow until the drawdown is manageable without incurring the added time of retracting and repositioning the downhole tool to another location within the wellbore.

FIG. 10 depicts a simplified schematic representation of an illustrative active port arrangement 1000 for targeted radial sampling with one active fluid port and three inactive fluid ports, according to one or more embodiments. The active port arrangement 1000 for targeted radial sampling with one active port can include a formation diagram 1010 with a sample area, a guard area, and a total area. In one or more embodiments, targeted radial sampling can be managed by configuring one fluid port into the open position 1020 and three fluid ports into the closed position 1030 to draw in fluid from a single direction in the formation relative to the downhole tool. In such embodiment, the open fluid port 1020 can be directed to an area of the formation that has the least resistance to fluid flow, thus enabling fluid sampling to be achieved at a faster rate. In other embodiments, the closed fluid ports 1030 can be directed to areas of the formation that have a greater resistance to fluid flow, thus preventing wasted fluid sampling efforts on less permeable regions of the formation.

FIG. 11 depicts a simplified schematic representation of an illustrative active port arrangement 1100 for managing ineffective or detrimental formation conditions using two active ports 1120 and two inactive fluid ports 1130, according to one or more embodiments. The active port arrangement 1100 can include a formation diagram 1110 with a total area, a tight formation section, and a rugose formation section. The ineffective or detrimental formation condition can include a tight formation section or a rugose formation section. The rugose formation section can include any formation characteristic that includes groves, roughness, pitting, and the like, or any combination thereof, such that the area around the port cannot seal when in contact with the formation. In one or more embodiments, the rugose formation can be managed by configuring two fluid ports into the open position 1120 and two fluid ports into the closed position 1130. The fluid ports in the closed position 1130 can contact the formation nearest the tight and rugose formation sections, respectively. The fluid ports in the open position 1120 can contact the formation in an area or region that can be located away from the tight and rugose formation sections, respectively. In one or more embodiments, the active port arrangement can be remotely configured to the open and/or the closed positions to avoid rugose and/or tight formation sections without needing to move the downhole tool.

FIG. 12 depicts a simplified schematic representation of an illustrative active port arrangement 1200 for managing a stuck downhole tool 1230, according to one or more embodiments. The active port arrangement 1200 can include a formation diagram 1210 with 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. The stuck downhole tool 1230 can include any downhole tool condition where the downhole tool 1230 has a blocked and/or plugged active port, the downhole tool 1230 has adhered and/or stuck to the side of the wellbore, and the like, or any combination thereof. The active port 1220 can include any active port being configured to change from the closed position to the open position and back to the closed position to force out a burst of injection fluid. In one or more embodiments, the active port 1220 can be rapidly selected and/or alternated between the open 1240 and the closed 1250 position. Such operation can be referred to as selectively “sneezing” or “cycling” the active port 1220 to remove material plugging the port and/or to push the downhole tool 1230 away from the wall of the wellbore. In one or more embodiments, the stuck downhole tool 1230 can be managed by cycling the active port 1220 between the active and inactive state to dislodge the downhole tool from the side of the wellbore and/or clear one or more fluid ports from any blockage or obstruction.

FIG. 13 depicts a simplified schematic representation of an illustrative active port arrangement 1300 for measuring azimuthal mobility of a downhole tool, according to one or more embodiments. The active port arrangement 1300 can include a formation diagram 1310 with a total area and directions along one or more axes and at least one remote sensor 1320. Measuring the azimuthal mobility can include determining the movement of the downhole tool before, during, and/or after intake and/or injection of fluid via the active port arrangement. The at least one remote sensor 1320 can 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 can be tracked or measured using the remote sensor(s) 1320 that can detect linear movement in 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 can provide fluid movement data in real time to a surface user to be used in future downhole operational planning and/or operation optimization. In some embodiments, measuring azimuthal mobility can determine fluid port orientation within a well. In some embodiments, knowing the orientation of the fluid ports and intaking and/or injecting fluid via one or mor of the fluid ports can provide information about the preferential direction of fluid flow. Such information can be used in carrying out downhole operations, e.g., for geo-steering and/or for guiding well placement.

All patents and patent applications, test procedures (such as ASTM methods, UL methods, and the like), and other documents cited herein are fully incorporated by reference to the extent such disclosure can be not inconsistent with this disclosure and for all jurisdictions in which such incorporation can be permitted.

Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges including the combination of any two values, e.g., the combination of any lower value with any upper value, the combination of any two lower values, and/or the combination of any two upper values are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more claims below.

The foregoing has also outlined features of several embodiments so that those skilled in the art can better understand the present disclosure. Those skilled in the art should appreciate that they can readily use the present disclosure as a basis for designing or modifying other methods or devices for carrying out the same purposes and/or achieving the same advantages of the embodiments disclosed herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they can make various changes, substitutions, and alterations herein without departing from the spirit and scope of the present disclosure, and the scope thereof can be determined by the claims that follow.

Claims

1. A downhole tool configured to be located in a wellbore traversing a formation to obtain a formation fluid sample located at a predetermined distance within the formation from a sidewall of the wellbore, the downhole tool comprising:

one or more fluid ports configured to receive a formation fluid, wherein at least one of the one or more fluid ports is configured to be in an open position; and

a fluid monitor configured to measure one or more formation fluid properties of the received formation fluid, wherein the one or more fluid ports are configured to be in the open state for a first period of time (t) such that the one or more fluid ports are configured to obtain formation fluid located at a first distance from the sidewall of the wellbore within the formation.

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

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

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 agents into the wellbore and/or into the formation.

5. The downhole tool of claim 4, wherein the at least one of the one or more fluid ports configured to inject the one or more agents into the wellbore and/or into the formation is configured to receive the one or more agents from a drilling site located at the surface 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 agents into the wellbore and/or into the formation.

7. The downhole tool of claim 6, wherein the one or more fluid injection ports is configured to receive the one or more agents from a drilling site located at the surface and/or from one or more storage compartments located within the downhole tool.

8. A process for obtaining a formation fluid, comprising:

locating a downhole tool within a wellbore traversing a formation, the downhole tool comprising one or more fluid ports and a fluid monitor;

obtaining a formation fluid via the one or more fluid ports, wherein the formation fluid is obtained for 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; and

analyzing the formation fluid 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 process of claim 8, wherein the formation fluid is obtained for a second period of time (t+Δt1) such that the formation fluid is obtained from the formation at a second distance from the sidewall of the wellbore.

10. The process of claim 9, wherein the formation fluid is obtained for a third period of time (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 process of any one of claims 8 to 10, wherein the formation fluid is analyzed using a numerical flow model.

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

13. The process of claim 11 or claim 12, wherein the numerical flow model includes a plurality of input variables that include a wellbore diameter, an initial formation pressure, a formation thickness, a formation porosity, a formation permeability, a formation fluid density, a formation fluid viscosity, a formation fluid compressibility, a fluid port geometry, and a downhole tool pumping rate.

14. The process of any one of claims 11 to 13, wherein the numerical flow model includes two coupled partial differential equations that describe the flow of formation fluid with the flow of a tracer to distinguish between formation fluid closer to the wellbore than a predetermined distance and the formation fluid further away from the wellbore than the predetermined distance.

15. The process of claim 14, wherein the tracer is computed as a mass-less component of the numerical flow model.

16. The process of any one of claims 11 to 15, wherein an output produced by the numerical flow model is used to determine a field development plan for the subsurface formation and/or a production plan for the subsurface formation.

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

18. The process of any one of claims 8 to 16, wherein the one or more fluid ports are further configured to inject one or more agents into the wellbore and/or into the formation, the process further comprising injecting one or more agents into the wellbore and/or into the formation via the one or more fluid ports prior to obtaining the formation fluid.

19. A downhole tool configured to be located in a wellbore traversing a formation to obtain a formation fluid sample located at a predetermined distance within the formation from a sidewall of the wellbore, the downhole tool comprising:

one or more fluid ports configured to receive a formation fluid from the formation, wherein the one or more fluid ports are remotely configurable to an open position or a closed position; and

a fluid monitor configured to measure one or more formation fluid properties of the 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 period of time (t) such that the at least one of the one or more fluid ports is configured to obtain formation fluid located at a first distance from the sidewall of the wellbore within the formation.

20-32. (canceled)

33. A process for unsticking a downhole tool, comprising:

determining a downhole tool within a wellbore traversing a formation is stuck to the side of the wellbore, the downhole tool comprising one or more fluid ports remotely configurable between an open position and a closed position; and

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 a fluid from the at least one of the one or more fluid ports in the open position for a duration of time; remotely configuring the at least one of the one or more fluid ports the closed position; and repeating the prior steps on the at least one of the one or more fluid ports until the downhole tool is no longer stuck.