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WO2024168259A1 - Outils d'échantillonnage de fluide de formation et procédés d'utilisation associés - Google Patents

Outils d'échantillonnage de fluide de formation et procédés d'utilisation associés Download PDF

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Publication number
WO2024168259A1
WO2024168259A1 PCT/US2024/015192 US2024015192W WO2024168259A1 WO 2024168259 A1 WO2024168259 A1 WO 2024168259A1 US 2024015192 W US2024015192 W US 2024015192W WO 2024168259 A1 WO2024168259 A1 WO 2024168259A1
Authority
WO
WIPO (PCT)
Prior art keywords
formation
fluid
downhole tool
wellbore
ports
Prior art date
Application number
PCT/US2024/015192
Other languages
English (en)
Inventor
Morten Kristensen
German Garcia
Ashers Partouche
Francois Xavier Dubost
Jonathan Leonard
Amir HERMES
Christopher Albert Babin
Original Assignee
Schlumberger Technology Corporation
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Schlumberger Technology Corporation, Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Technology B.V. filed Critical Schlumberger Technology Corporation
Publication of WO2024168259A1 publication Critical patent/WO2024168259A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
    • E21B49/10—Obtaining fluid samples or testing fluids, in boreholes or wells using side-wall fluid samplers or testers

Definitions

  • 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.
  • 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 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.
  • a 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.
  • 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 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.
  • 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.
  • 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.
  • a process for obtaining a formation fluid 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.
  • a process for unsticking a downhole tool 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.
  • 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.
  • 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.
  • 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.
  • the wellbore 120 can be for the production of oil and/or gas.
  • the wellbore 120 can be utilized for carbon capture and storage.
  • 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.
  • 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.
  • 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.
  • the target radius 101 can be located within the invasive fluid region 140.
  • the target radius 102 can be located at or close to the maximum invasion radius 113.
  • 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.
  • the fluid intake port arrangement 210 can include a single port, as described in U.S. Patent No. 11,280,191 B2 and/or U.S. Patent No. 8,453,732 B2.
  • the fluid intake port arrangement 220 can include four intake ports, as described in U.S. Patent Application Publication No.
  • the third fluid intake port arrangement 230 can include two ports, as described in U. S. Patent Application Publication No. 2021/0293122 Al, that can be located around the downhole tool with equal spacing between each port.
  • the fourth fluid intake port arrangement 240 can include a single port, as described in U.S. Patent Application No. 2021/0293122 Al.
  • 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.
  • 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.
  • 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.
  • the non-formation fluid(s) and formation fluid can be in their original position before the downhole tool begins operation.
  • the maximum invasion radius 113 can be 90 inches from the outer edge of the sidewall 111.
  • 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.
  • the downhole tool can be in operation for a time where the transitory zone 305 has been drawn into the downhole tool.
  • 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.
  • 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.
  • the fluid intake port arrangement 240 can reach the fluid fraction threshold of 1% more quickly than other fluid intake port arrangements.
  • the downhole tool can include a fluid monitor to analyze the fluids drawn into the downhole tool.
  • the fluid monitor can be used to analyze or otherwise estimate any number of properties of the fluids drawn into the downhole tool.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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).
  • the given radius R can be varied to determine the variability of arrival time (t) as a function of depth within the formation 100.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the agent can be non-reactive or reactive with one or more elements or compounds located within the formation 100.
  • the agent can be a gas, a liquid, a solid, or a multi -phase composition.
  • the agent can be a surfactant or other chemical.
  • 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).
  • the agent can act or serve as a tracer material.
  • the agent can be an acid compound or a base compound.
  • 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 (PDMC)
  • PDMC perflurocarbon
  • the tracer that can be computed as a mass-less component of the numerical flow model can be the agent intentionally injected into the wellbore 120 and/or the formation 100 via the downhole tool 600.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • a given depth may be deemed as “non-testable” due to low permeability (excessive drawdown).
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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 inj ection 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.
  • 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.
  • 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.
  • measuring azimuthal mobility can determine fluid port orientation within a well.
  • 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.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics (AREA)
  • Sampling And Sample Adjustment (AREA)

Abstract

Outil de fond configuré pour être situé dans un puits de forage traversant une formation pour obtenir un échantillon de fluide de formation. Dans certains modes de réalisation, l'outil de fond peut comprendre un ou plusieurs orifices d'entrée de fluide configurés pour recevoir un fluide de formation et un dispositif de surveillance de fluide qui peut être configuré pour mesurer une ou plusieurs propriétés de fluide de formation du fluide de formation reçu. Le ou les orifices d'entrée de fluide peuvent se trouver dans une position ouverte. Le ou les orifices d'entrée de fluide peuvent se trouver dans la position ouverte pendant une première période (t) de sorte que le ou les orifices d'entrée de fluide sont configurés pour obtenir un fluide de formation situé à une première distance de la paroi latérale du puits de forage à l'intérieur de la formation.
PCT/US2024/015192 2023-02-10 2024-02-09 Outils d'échantillonnage de fluide de formation et procédés d'utilisation associés WO2024168259A1 (fr)

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Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP1334261B1 (fr) * 2000-10-27 2006-01-04 Baker Hughes Incorporated Appareil et procede d'essai des formations en cours de forage a l'aide d'une mesure de la pression absolue et differentielle
WO2014133764A1 (fr) * 2013-02-27 2014-09-04 Schlumberger Canada Limited Méthodes d'analyse de fluide de fond de trou
US20170177761A1 (en) * 2015-12-18 2017-06-22 Baker Hughes Incorporated Integrated modeling and simulation of formation and well performance
US20170175524A1 (en) * 2015-12-18 2017-06-22 Schlumberger Technology Corporation Systems and Methods for In-Situ Measurements of Mixed Formation Fluids
US20210131284A1 (en) * 2016-10-10 2021-05-06 Halliburton Energy Services, Inc. Method and system for extracting reservoir fluid sample

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP1334261B1 (fr) * 2000-10-27 2006-01-04 Baker Hughes Incorporated Appareil et procede d'essai des formations en cours de forage a l'aide d'une mesure de la pression absolue et differentielle
WO2014133764A1 (fr) * 2013-02-27 2014-09-04 Schlumberger Canada Limited Méthodes d'analyse de fluide de fond de trou
US20170177761A1 (en) * 2015-12-18 2017-06-22 Baker Hughes Incorporated Integrated modeling and simulation of formation and well performance
US20170175524A1 (en) * 2015-12-18 2017-06-22 Schlumberger Technology Corporation Systems and Methods for In-Situ Measurements of Mixed Formation Fluids
US20210131284A1 (en) * 2016-10-10 2021-05-06 Halliburton Energy Services, Inc. Method and system for extracting reservoir fluid sample

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