FLUID SAMPLING TOOL

Abstract

The present disclosure relates to one or more an apparatuses including a downhole tool configured for conveyance in a wellbore extending into a subterranean formation. The downhole tool may include a first unit having a first fluid port configured to provide fluid communication between the first unit and the wellbore, a second unit having a second fluid port configured to provide fluid communication between the second unit and the wellbore, a connector configured to connect a first connecting end of the first unit with a second connecting end of the second unit, such that the connector does not include packer elements, a first packer element mounted on the first unit and not located between the first fluid port and the first connecting end, and a second packer element mounted on the second unit and not located between the second fluid port and the second connecting end.

Description

BACKGROUND OF THE DISCLOSURE

Wellbores are generally drilled into the ground or ocean bed to recover natural deposits of oil and gas, as well as other desirable materials that are trapped in geological formations in the Earth's crust. Wellbores are typically drilled using a drill bit attached to the lower end of a “drill string.” Drilling fluid, or mud, is typically pumped down through the drill string to the drill bit. The drilling fluid lubricates and cools the bit, and may additionally carry drill cuttings from the wellbore back to the surface.

In various oil and gas exploration operations, it may be beneficial to have information about the subterranean formations that are penetrated by a wellbore. For example, certain formation evaluation schemes may include measurement and analysis of the formation pressure and permeability and/or of formation fluids. These measurements may be essential to making predictions, such as the production capacity and production lifetime of the subterranean formation. Thus, reservoir well creation and testing may involve drilling into the subterranean formation and monitoring of various subterranean formation parameters.

When drilling and monitoring, downhole tools having electric, mechanic, and/or hydraulic powered devices may be used. In some implementations, pump systems may be used to draw or pump fluid from subterranean formations. For example, a downhole string (e.g., a drill string, coiled tubing, slickline, wireline, etc.) may include one or more pump systems depending on the operations to be performed by the downhole string. Fluid drawn or pumped from subterranean formation may include hydrocarbon fluids such as dry natural gas, wet gas, condensate, light oil, black oil, heavy oil, and heavy viscous tar. In addition, water and synthetic fluids, such as oils used within drilling muds, and fluids used in formation fracturing jobs, may also be present in the fluid drawn or pumped from the subterranean formations.

As the economic value of a hydrocarbon reserve, the method of production, the efficiency of recovery, the design of production equipment, in addition to a number of other factors, all depend upon a number parameters of the formation fluid, such as composition, phase behavior and flow rates, it is useful that the formation fluid parameters are determined accurately. As such, it may be valuable to analyze samples of fluids, for example, to assist in determining the value of a hydrocarbon reserve or in determining a preferred method of extraction.

Advanced formation testing tools have been used, for example, to capture fluid samples from subterranean earth formations. Formation testing tools may be typically equipped with a device, such as a straddle or dual packer. Straddle or dual packers may include two inflatable sleeves around the formation testing tool, in which the packers, when inflated, make contact with the earth formation and seal an interval of the wellbore. The testing tool may include a port and a flow line communicating with the sealed interval, in which a fluid communication is established between the sealed interval and the testing tool.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIG. 2 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIG. 3 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIG. 4 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIG. 5 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIG. 6 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIGS. 7A and 7B are schematics of apparatus according to one or more aspects of the present disclosure.

FIGS. 8A and 8B are schematics of apparatus according to one or more aspects of the present disclosure.

FIG. 9 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIG. 10 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIG. 11 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIG. 12 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIG. 13 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIG. 14 is a schematic of apparatus according to one or more aspects of the present disclosure.

FIG. 15 is a schematic of apparatus according to one or more aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. 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 discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

Referring to FIG. 1, illustrated is a side view of a wellsite 100 having a drilling rig 110 with a drill string 112 suspended therefrom in accordance with one or more aspects of the present disclosure. The wellsite 100 shown, or one similar thereto, may be used within onshore and/or offshore locations. A wellbore 114 may be formed within a subterranean formation F, such as by using rotary drilling, or any other method known in the art. As such, one or more aspects of the present disclosure may be used within a wellsite, similar to the one as shown in FIG. 1 (discussed more below). One or more aspects of the present disclosure may also be used within other wellsites or drilling operations, such as within a directional drilling application, without departing from the scope of the present disclosure.

Continuing with FIG. 1, the drill string 112 may suspend from the drilling rig 110 into the wellbore 114. The drill string 112 may include a bottom hole assembly 118 and a drill bit 116, in which the drill bit 116 may be disposed at an end of the drill string 112. The surface of the wellsite 100 may have the drilling rig 110 positioned over the wellbore 114, and the drilling rig 110 may include a rotary table 120, a kelly 122, a traveling block or hook 124, and may additionally include a rotary swivel 126. The rotary swivel 126 may be suspended from the drilling rig 110 through the hook 124, and the kelly 122 may be connected to the rotary swivel 126 such that the kelly 122 may rotate with respect to the rotary swivel.

An upper end of the drill string 112 may be connected to the kelly 122, such as by threadingly connecting the drill string 112 to the kelly 122, and the rotary table 120 may rotate the kelly 122, thereby rotating the drill string 112 connected thereto. As such, the drill string 112 may be able to rotate with respect to the hook 124. However, though a rotary drilling system is shown in FIG. 1, other drilling systems may be used without departing from the scope of the present disclosure. For example, a top-drive (also known as a “power swivel”) system may be used without departing from the scope of the present disclosure. In such a top-drive system, the hook 124, swivel 126, and kelly 122 are replaced by a drive motor (electric or hydraulic) that may apply rotary torque and axial load directly to drill string 112.

The wellsite 100 may include drilling fluid 128 (also known as drilling “mud”) stored in a pit 130. The pit 130 may be formed adjacent to the wellsite 100, as shown, in which a pump 132 may be used to pump the drilling fluid 128 into the wellbore 114. The pump 132 may pump and deliver the drilling fluid 128 into and through a port of the rotary swivel 126, thereby enabling the drilling fluid 128 to flow into and downwardly through the drill string 112, the downward flow of the drilling fluid 128 being indicated generally by direction arrow 134. This drilling fluid 128 may then exit the drill string 112 through one or more ports disposed within and/or fluidly connected to the drill string 112. For example, the drilling fluid 128 may exit the drill string 112 through one or more ports formed within the drill bit 116.

As such, the drilling fluid 128 may flow back upwardly through the wellbore 114, such as through an annulus 136 formed between the exterior of the drill string 112 and the interior of the wellbore 114, the upward flow of the drilling fluid 128 being indicated generally by direction arrow 138. With the drilling fluid 128 following the flow pattern indicted by the direction arrows 134 and 138, the drilling fluid 128 may be able to lubricate the drill string 112 and the drill bit 116, and/or may be able to carry formation cuttings formed by the drill bit 116 (or formed by any other drilling components disposed within the wellbore 114) back to the surface of the wellsite 100. As such, this drilling fluid 128 may be filtered and cleaned and/or returned back to the pit 130 for recirculation within the wellbore 114.

Though not shown, the drill string 112 may include one or more stabilizing collars. A stabilizing collar may be disposed within and/or connected to the drill string 112, in which the stabilizing collar may be used to engage and apply a force against the wall of the wellbore 114. This may enable the stabilizing collar to prevent the drill string 112 from deviating from the desired direction for the wellbore 114. For example, during drilling, the drill string 112 may “wobble” within the wellbore 114, thereby allowing the drill string 112 to deviate from the desired direction of the wellbore 114. This wobble action may also be detrimental to the drill string 112, components disposed therein, and the drill bit 116 connected thereto. However, a stabilizing collar may be used to minimize, if not overcome altogether, the wobble action of the drill string 112, thereby possibly increasing the efficiency of the drilling performed at the wellsite 100 and/or increasing the overall life of the components at the wellsite 100.

As discussed above, the drill string 112 may include a bottom hole assembly 118, such as by having the bottom hole assembly 118 disposed adjacent to the drill bit 116 within the drill string 112. The bottom hole assembly 118 may include one or more components included therein, such as components to measure, process, and store information. The bottom hole assembly 118 may include components to communicate and relay information to the surface of the wellsite.

As such, as shown in FIG. 1, the bottom hole assembly 118 may include one or more logging-while-drilling (“LWD”) tools 140 and/or one or more measuring-while-drilling (“MWD”) tools 142. The bottom hole assembly 118 may also include a steering-while-drilling system (e.g., a rotary-steerable system) and motor 144, in which the rotary-steerable system and motor 144 may be coupled to the drill bit 116.

The LWD tool 140 shown in FIG. 1 may include a thick-walled housing, commonly referred to as a drill collar, and may include one or more of a number of logging tools known in the art. Thus, the LWD tool 140 may be capable of measuring, processing, and/or storing information therein, as well as capabilities for communicating with equipment disposed at the surface of the wellsite 100.

The MWD tool 142 may also include a housing (e.g., drill collar), and may include one or more of a number of measuring tools known in the art, such as tools used to measure characteristics of the drill string 112 and/or the drill bit 116. The MWD tool 142 may also include an apparatus for generating and distributing power within the bottom hole assembly 118. For example, a mud turbine generator powered by flowing drilling fluid therethrough may be disposed within the MWD tool 142. Alternatively, other power generating sources and/or power storing sources (e.g., a battery) may be disposed within the MWD tool 142 to provide power within the bottom hole assembly 118. As such, the MWD tool 142 may include one or more of the following measuring tools: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, an inclination measuring device, and/or any other device known in the art used within an MWD tool.

Referring to FIG. 2, illustrated is a side view of a tool 200 in accordance with one or more aspects of the present disclosure. The tool 200 may be connected to and/or included within a drill string 202, in which the tool 200 may be disposed within a wellbore 204 formed within a subterranean formation F. As such, the tool 200 may be included and used within a bottom hole assembly, as described above.

Particularly, the tool 200 may include a sampling-while drilling (“SWD”) tool, such as that described in U.S. Pat. No. 7,114,562, filed on Nov. 24, 2003, entitled “Apparatus and Method for Acquiring Information While Drilling,” and incorporated herein by reference in its entirety. As such, the tool 200 may include a probe 210 to hydraulically establish communication with the formation F and draw formation fluid 212 into the tool 200.

The tool 200 may also include a stabilizer blade 214 and/or one or more pistons 216. As such, the probe 210 may be disposed on the stabilizer blade 214 and extend therefrom to engage the wall of the wellbore 204. The pistons, if present, may also extend from the tool 200 to assist probe 210 in engaging with the wall of the wellbore 204. Alternatively, though, the probe 210 may not necessarily engage the wall of the wellbore 204 when drawing fluid.

As such, fluid 212 drawn into the tool 200 may be measured to determine one or more parameters of the formation F, such as pressure and/or pretest parameters of the formation F. Additionally, the tool 200 may include one or more devices, such as sample chambers or sample bottles, that may be used to collect formation fluid samples. These formation fluid samples may be retrieved back at the surface with the tool 200. Alternatively, rather than collecting formation fluid samples, the formation fluid 212 received within the tool 200 may be circulated back out into the formation F and/or wellbore 204. As such, a pumping system may be included within the tool 200 to pump the formation fluid 212 circulating within the tool 200. For example, the pumping system may be used to pump formation fluid 212 from the probe 210 to the sample bottles and/or back into the formation F. Alternatively still, rather than collecting formation fluid samples, a tool in accordance with aspects disclosed herein may be used to collect samples from the formation F, such as one or more coring samples from the wall of the wellbore 204.

Referring to FIG. 3, illustrated is a schematic view of a tool 300 in accordance with one or more aspects of the present disclosure. The tool 300 may be connected to and/or included within a bottom hole assembly, in which the tool 300 may be disposed within a wellbore 304 formed within a subterranean formation F.

The tool 300 may be a pressure LWD tool used to measure one or more downhole pressures, including annular pressure, formation pressure, and pore pressure, before, during, and/or after a drilling operation. Other pressure LWD tools may also be utilized in one or more aspects, such as that described in U.S. Pat. No. 6,986,282, filed on Feb. 18, 2003, entitled “Method and Apparatus for Determining Downhole Pressures During a Drilling Operation,” and incorporated herein by reference in its entirety.

As shown, the tool 300 may be formed as a modified stabilizer collar 310 and may have a passage 312 formed therethrough for drilling fluid. The flow of the drilling fluid through the tool 300 may create an internal pressure P₁, and the exterior of the tool 300 may be exposed to an annular pressure P_A of the surrounding wellbore 304. A differential pressure P_δ formed between the internal pressure P₁ and the annular pressure P_A may then be used to activate one or more pressure devices 316 that may be included within the tool 300.

The tool 300 may include two pressure measuring devices 316A and 316B that may be disposed on stabilizer blades 318 formed on the stabilizer collar 310. The pressure measuring device 316A may be used to measure the annular pressure P_A in the wellbore 304, and/or may be used to measure the pressure of the formation F when positioned in engagement with a wall 306 of the wellbore 304. As shown in FIG. 3, the pressure measuring device 316A is not in engagement with the wellbore wall 306, thereby enabling the pressure measuring device 316A to measure the annular pressure P_A, if desired. However, when the pressure measuring device 316A is moved into engagement with the wellbore wall 306, the pressure measuring device 316A may be used to measure pore pressure of the formation F.

As also shown in FIG. 3, the pressure measuring device 316B may be extendable from the stabilizer blade 318, such as by using a hydraulic control disposed within the tool 300. As such, a pumping system may be included within the tool 300, such as including the pumping system within one or more of the pressure devices 316 for activation and/or movement of the pressure devices 316. When extended from the stabilizer blade 318, the pressure measuring device 316B may establish sealing engagement with the wall 306 of the wellbore 304 and/or a mudcake 308 of the wellbore 304. This may also enable the pressure measuring device 316B to take measurements of the formation F. Other controllers and circuitry, not shown, may be used to couple the pressure measuring devices 316 and/or other components of the tool 300 to a processor and/or a controller. The processor and/or controller may then be used to communicate the measurements from the tool 300 to other tools within a bottom hole assembly or to the surface of a wellsite.

Referring to FIG. 4, illustrated is a side view of a tool 400 in accordance with one or more aspects of the present disclosure. The tool 400 may be a “wireline” tool, in which the tool 400 may be suspended within a wellbore 404 formed within a subterranean formation F. As such, the tool 400 may be suspended from an end of a multi-conductor cable 406, such as by having the multi-conductor cable 406 spooled around a winch (not shown) disposed on the surface of the formation F. The multi-conductor cable 406 is then coupled the tool 400 with an electronics and processing system 408 disposed on the surface.

The tool 400 may have an elongated body 410 that includes a formation tester 412 disposed therein. The formation tester 412 may include an extendable probe 414 and an extendable anchoring member 416, in which the probe 414 and anchoring member 416 may be disposed on opposite sides of the body 410. One or more other components 418, such as a measuring device, may also be included within the tool 400.

The probe 414 may be included within the tool 400 such that the probe 414 may be able to extend from the body 410 and then selectively seal off and/or isolate selected portions of the wall of the wellbore 404. This may enable the probe 414 to establish pressure and/or fluid communication with the formation F to draw fluid samples from the formation F. The tool 400 may also include a fluid analysis tester 420 that is in fluid communication with the probe 414, thereby enabling the fluid analysis tester 420 to measure one or more properties of the fluid. The fluid from the probe 414 may also be sent to one or more sample chambers or bottles 422, which may receive and retain fluids obtained from the formation F for subsequent testing after being received at the surface. The fluid from the probe 414 may also be sent back out into the wellbore 404 or formation F.

Referring to FIG. 5, illustrated is a side view of another tool 500 in accordance with one or more aspects of the present disclosure. The tool 500 may be suspended within a wellbore 504 formed within a subterranean formation F using a multi-conductor cable 506. The multi-conductor cable 506 may be supported by a drilling rig 502.

The tool 500 may include one or more packers 508 that may be configured to inflate, thereby selectively sealing off a portion of the wellbore 504 around the tool 500, and between the tool 500 and the formation F. To test the formation F, the tool 500 may include one or more probes 510, and the tool 500 may also include one or more outlets 512 that may be used to inject fluids within the wellbore portion sealed off by the packers 508.

Referring to FIG. 6, illustrated is a side view of a wellsite 600 having a drilling rig 610 in accordance with one or more aspects of the present disclosure. A wellbore 614 may be formed within a subterranean formation F, such as by using a drilling assembly, or any other method known in the art. A wired pipe string 612 may be suspended from the drilling rig 610. The wired pipe string 612 may be extended into the wellbore 614 by threadably coupling multiple segments 620 (i.e., joints) of wired drill pipe together in an end-to-end fashion. As such, the wired drill pipe segments 620 may be similar to the wired drill pipe segments described in U.S. Pat. No. 6,641,434, filed on May 31, 2002, entitled “Wired Pipe Joint with Current-Loop Inductive Couplers,” and incorporated herein by reference in its entirety.

Wired drill pipe may be structurally similar to typical drill pipe, however the wired drill pipe may additionally include a cable installed therein to enable communication through the wired drill pipe. The cable installed within the wired drill pipe may be any type of cable capable of transmitting data and/or signals therethrough, such an electrically conductive wire, a coaxial cable, an optical fiber cable, and or any other cable known in the art. The wired drill pipe may include a form of signal coupling, such as inductive coupling, to communicate data and/or signals between adjacent pipe segments assembled together.

As such, the wired pipe string 612 may include one or more tools 622 and/or instruments disposed within the pipe string 612. For example, as shown in FIG. 6, a string of multiple wellbore tools 622 may be coupled to a lower end of the wired pipe string 612. The tools 622 may include one or more tools used within wireline applications, may include one or more LWD tools, may include one or more formation evaluation or sampling tools, and/or may include any other tools capable of measuring a characteristic of the formation F.

The tools 622 may be connected to the wired pipe string 612 during drilling the wellbore 614, or, if desired, the tools 622 may be installed after drilling the wellbore 614. If installed after drilling the wellbore 614, the wired pipe string 612 may be brought to the surface to install the tools 622, or, alternatively, the tools 622 may be connected or positioned within the wired pipe string 612 using other methods, such as by pumping or otherwise moving the tools 622 down the wired pipe string 612 while still within the wellbore 614. The tools 622 may then be positioned within the wellbore 614, as desired, through the selective movement of the wired pipe string 612, in which the tools 622 may gather measurements and data. These measurements and data from the tools 622 may then be transmitted to the surface of the wellbore 614 using the cable within the wired drill pipe 612.

As such, a downhole tool to sample formation fluids, such as a fluid sampling tool, may be included within one or more of the tools shown in FIGS. 1-6, in addition to being included within other tools and/or devices that may be configured for conveyance in a wellbore extending into a subterranean formation. A downhole tool (hereinafter referred to as a “fluid sampling tool”), thus, may be used to sample one or more fluids that may be confined in an sealed off interval of a wellbore extending in a subterranean formation. The fluid sampling tool may include one or more fluid ports that may allow fluid to be withdrawn from the interval and/or may allow for fluid to be injected into the interval.

The fluid sampling tool may include fluid sampling units that may include one or more packer elements and/or one or more fluid ports. In accordance with one or more aspects of the present disclosure, the fluid sampling tool may include a first fluid sampling unit and a second fluid sampling unit. The two fluid sampling units may be connected by a connecting section that may include an adapter, fluid ports, valves, pumps, and/or any other downhole tools and/or instruments.

In accordance with one or more aspects of the present disclosure, the fluid sampling tool may include first and second units having fluid ports. The fluid ports may provide for fluid communication between the first and second units and the wellbore into which the fluid sampling tool may be disposed. A connector or connecting portion may be provided to connect the first unit with the second unit. A first packer element and a second packer element may be mounted to the first and second units, respectively. The connector, connecting the first and second units, may not have packer elements as a part thereof. The first and second packer elements may be located such that the first and second packer elements are not located between the fluid ports of the first and second elements, respectively, and the connector. The first and second units may be elements of downhole tools, such as unitary mandrels. The connector or connecting portion may provide one of a male-male and a female-female connection, to thereby connect two units.

According to one or more aspects disclosed herein, an interval from which formation fluids may be sampled may be created by the packer elements attached to, mounted to, and/or integrally part of, the fluid sampling units. More particularly, the packer elements attached to the first and second fluid sampling units may be configured to fluidly seal off an interval of the wellbore from the remainder of the wellbore. The two packer elements may define the interval within the wellbore, such as an 18-30 inch (45-77 cm) interval of the wellbore, from which fluids may be sampled. However, any range or size for the interval may be created by use of fluid sampling units in accordance with the present disclosure. Further, while inflatable packer elements are depicted in the accompanying figures, the packer elements may be any type of packer element known in the art, including inflatable packers, hydraulic packers, squeeze packers, and/or any other type of packer that may create a fluidly sealed interval in a wellbore. Additionally, other methods and/or devices may be employed to create a fluidly sealed interval without departing from the scope of the present disclosure.

According to one or more aspects disclosed herein, the fluid sampling tools are not restricted to two packers and/or two fluid sampling units. For example, fluid sampling tools may include more than two packers, such as shown in U.S. Pat. No. 4,353,249, filed on Oct. 30, 1980, entitled “Method and Apparatus for In Situ Determination of Permeability and Porosity,” U.S. Pat. No. 4,392,376, filed on Mar. 31, 1981, entitled “Method and Apparatus for Monitoring Borehole Conditions,” U.S. Pat. No. 6,301,959, filed on Jan. 26, 1999, entitled “Focused Formation Fluid Sampling Probe,” and U.S. Pat. No. 6,065,544, filed on Mar. 26, 1998, entitled “Method and Apparatus for Multiple Packer Pressure Relief,” and incorporated herein by reference in their entireties. Further, in one or more aspects of the present disclosure, packers may include multiple flow paths and/or fluid ports embedded in the packer elements.

The packer elements of fluid sampling units and/or fluid sampling tools disclosed herein may be selectively operable, such that an operator may inflate and/or deflate (or operate) the packer elements to provide engagement with a wellbore wall or to withdraw the packer elements from engagement. For example, a fluid pump may be provided to pump fluid into inflatable packer elements to provide engagement with a wellbore wall. The pump may be configured to withdraw fluid from the packer elements to deflate the packer elements and allow for retrieval of a downhole tool. Exit ports may be provided to allow for fluid communication between the packer elements and an annulus region of the wellbore. As noted above, the present disclosure is not limited to inflatable packer elements. For example, other packer elements or other sealing methods and/or devices may be used in addition or in lieu of inflatable packers.

Fluid sampling units and/or fluid sampling tools in accordance with one or more aspects of the present disclosure may include a single fluid port in the lower part of the interval, such that when a sampling operation is in process, a pump of the fluid sampling unit and/or the fluid sampling tool may tend to draw fluid from the lower portion of the interval. However, a single fluid port may be disposed at any location in the interval such that a particular source of fluid may be selected, or a particular point of injection from the fluid port may be used. An interval length may be set at the surface before deployment downhole by setting the spacing between two fluid sampling units, and, therefore, between two packer elements. A connecting section may couple the two fluid sampling units and may include a flow line and/or other fluid coupling and/or fluid communicating tools. For example, the connecting section may include pipe sections, fluid ports, adapters, pumps, valves, fluid analysis tools and/or any other downhole tools as may be required for fluid sample collection and/or fluid communication, among other functions.

Fluid sampling units and/or fluid sampling tools in accordance with one or more aspects of the present disclosure may be conveyed downhole on the end of a wireline cable. Although described herein as disposed at the end of a wireline cable, the fluid sampling units and/or the fluid sampling tools disclosed herein may be disposed on a drill string or on a wired drill string or other downhole device. The fluid sampling units disclosed herein may be conveyed downhole by any conveyance means without departing from the scope of the present disclosure.

Once downhole, the packer elements of the fluid sampling units and/or the fluid sampling tools may be extended into fluid sealing engagement with the wellbore wall. After an interval is fluidly sealed by the packer elements, the interval may be filled with fluid from the subterranean formation. The formation fluid may enter the interval through cracks and/or pores already present in the formation and the wellbore, or the pores and/or cracks may be generated by any known means, for example, pressure provided by inflation of the packer elements, use of a coring tool, or by use of a fracturing device or method. Formation fluid may enter the fluid sampling units and/or the fluid sampling tools by one or more of the fluid ports of the fluid sampling units or the connecting portion disposed therebetween. As such, a fluid pumping system may be provided to pump formation fluid into and/or through the fluid ports. The fluid ports of the fluid sampling units may serve as inlets and/or outlets, and may be connected to a flow line formed in the fluid sampling units and/or the connecting portion. The flow line may provide fluid coupling between the separate fluid sampling units and connecting section.

In one or more aspects of the present disclosure, fluid ports may be connected by use of a connecting portion including an adapter. Two fluid ports may be provided between two packer elements by use of an adapter. For example, the adapter may include a fluid port. Alternatively, an adapter may be configured to attach two sampling units, each having a fluid port, so that the fluid ports of the sampling unit are located adjacent the adapter. In this case, the adapter may be one of a male-male and female-female adapter. Other types of adapters may also and/or alternatively be used. For example, the interval may be adjustable by use of an extendable adapter such as described in U.S. Pat. No. 7,647,980, filed on May 29, 2007, entitled “Drillstring Packer Assembly,” assigned to Schlumberger Technology Corporation and incorporated herein by reference in its entirety. Moreover, other types and forms of adapters may be used without departing from the scope of the present disclosure.

In one or more aspects of the present disclosure, two or more fluid ports may be provided in an interval sealed between two adjacent packers by use of two fluid sampling units connected together. Accordingly, a first fluid sampling unit may be employed having a first packer element and a first fluid port. A second fluid sampling unit may be employed having a second packer element and a second fluid port. In this configuration, a connecting portion may be installed between the two fluid sampling units that may have a female-female or male-male connector to thereby connect the two units. Each section, including the first fluid sampling unit, the second sampling unit, and the connecting portion may include one or more flow lines that may be connected and/or otherwise fluidly coupled. Alternatively, it may be preferable to prevent fluid communication between the flow line of the first fluid sampling unit and the flow line of the second sampling unit. Accordingly, the flow line of the connecting portion may be plugged, or may not be present, thereby preventing fluid communication between the two fluid sampling units.

The connecting portion or connector may include adapters such as mandrels, rotatable joints, and/or other connectors known in the art, which may not include a flow line formed therein, thereby preventing fluid communication between the first and second fluid sampling units. Alternatively, for example, the two fluid sampling units may be connected by use of dummy mandrels and/or fluid communicating adapters that may have flow lines formed therein, thereby allowing fluid communication between the two fluid sampling units. The length of the entire assembly may be modifiable and custom fit to a desired length by modifying and/or altering the length of the connecting portion, or elements thereof.

One or more aspects of the present disclosure may include a minimal adapter and/or connector. In this configuration the two fluid sampling units may be connected such that a very small interval may be created. Specifically, an adapter and/or connector located between the two fluid sampling units may include few or no additional tools or elements to thereby limit the length of the connecting portion. However, the connecting portion, even if minimal, may allow for one or more fluid ports to be located within the interval. The adapter and/or connector of the connecting portion may include an operable valve that may allow for an operator to seal the flow line between the two fluid sampling units, thereby enabling for separate samplings or measurements to be obtained. Alternatively, the flow line of the connecting portion between the fluid sampling units may be open, allowing for a mixture of the fluid that passes through each of the fluid ports and may therefore combine to form a fluid that may be characteristic of the entire interval sealed between two adjacent packers.

The fluid port(s) of the fluid sampling units may be provided at locations on the fluid sampling unit such that the fluid ports may be located anywhere in the interval sealed between two adjacent packers. A fluid port located near the packer of the first (or upper) fluid sampling unit may draw fluid from, or provide fluid to, the top of the sealed interval. In this case, if settling of the fluid in the sealed interval occurs, the less dense fluid may be extracted or fluid may be pumped into the less dense fluid of the sealed interval. A fluid port located near the packer of the second (or lower) fluid sampling unit may draw fluid from, or provide fluid to, the bottom of the sealed interval. In this case, if settling occurs of the fluid in the sealed interval, the more dense fluid may be extracted or fluid may be pumped into the more dense fluid of the sealed interval. A fluid port may be provided at any position within the sealed interval to extract fluid from, or inject fluid into, the sealed interval at desired positions.

Fluid ports may be provided with adapters to allow for extraction/injection at a location that is not directly at the fluid port. For example, a fluid port may be disposed on the tool body at a single location at approximately the middle of the tool body or middle of the connecting portion. The fluid port may be provided with an adapter to allow for fluid communication with any other point in the sealed interval. An upward adapter may be provided to allow for the fluid port to be in fluid communication with a point higher in the sealed interval than the fluid port, and/or a downward adapter may be provided to allow for the fluid port to be in fluid communication with a point lower in the sealed interval than the fluid port. Therefore, a single fluid port may be adapted to be in fluid communication with a point of the sealed interval different from the location of the fluid port on the tool body.

The fluid port(s) of the fluid sampling units, or located on the connecting portion, may be selectively operable (e.g., opened, throttled or closed). The fluid ports may be powered by electrical power provided from a wireline or wired drill pipe or by power provided on a downhole tool, or may be operable with fluid pressure, or by any other means known in the art. Accordingly, an operator may be able to selectively determine where and when a fluid sample is collected from, or where a fluid injection is injected to, the sealed interval. Accordingly, a desired sample, which may be characteristic of fluids in the formation, may be extracted for analysis.

Fluid analysis may be achieved through collection of fluid samples. Therefore, the fluid ports may be in fluid communication with a plurality of downhole tools by means of a flow line that passes through the fluid sampling units and/or the connecting portion. The downhole tools may include sample chambers and/or pumps configured to collect fluid that may be stored and/or conveyed to other downhole tools or to the surface. The downhole tools may also include tools to analyze, treat, or otherwise interact with any collected fluid samples. The fluid samples may be retained in sample chambers in downhole tools. Alternatively, the fluid samples may be conveyed to the surface and retained. Alternatively, the fluid samples may be circulated through instruments downhole or on the surface, and then re-injected back into the sealed interval, into other intervals or regions of the wellbore, into the formation, or anywhere else that may be desired.

In one or more aspects of the present disclosure, a controllable valve system may be employed within or in conjunction with the connecting portion. The controllable valve system may allow for control over the flow of fluid within and through the flow line, for example, to and/or from the fluid ports and with other downhole tools. An operator may control the controllable valve system to allow for pumping or extraction of fluid from or through any fluid port and in any direction (up or down in the flow line). Accordingly, an operator may selectively operate the valve system to allow for fluid from different positions in the sealed interval to be sent to different locations or instruments in the downhole tool, to the surface, to other intervals or regions in the wellbore, or any combination thereof. One or more valves may be employed in the valve system. Moreover, one or more of the valves of the valve system may also include fluid ports, thereby incorporating fluid ports into the connecting portion. The valve system may be powered similar to the power provided to the fluid ports as discussed above.

As noted, the valves and/or valve system may be selectively operable or controllable. Control may be provided by mechanical and/or electrical means, such as by pressure activation and/or by a microprocessor. Control may be made with downhole or wellsite surface mechanisms, and may be powered from downhole power sources and/or from power provided from the surface of the wellsite. A controllable valve system may be controlled by a computer located at the surface of the wellsite and/or downhole, which may be automated and/or manually operated. Similar control systems and/or mechanisms described herein may be used for controlling valves, fluid ports, pumps, and/or any other controllable elements in a downhole tool.

As disclosed herein, a tool body may include multiple tools and/or tool bodies that may be combined, attached, or in communication with each other, such that a singular tool body may be formed. The tool body, therefore, may include pipe sections, mandrels, ports, adapters, components, and/or any other necessary tool or piece to provide function or structure to a downhole tool (for example, see, FIG. 15). A tool body or downhole tool may have a longitudinal axis therethrough, whereby elements of the tool body or downhole tool may be displaced at locations with relation to the longitudinal axis.

Referring to FIGS. 7A and 7B, illustrated are schematics of a downhole tool 700 in accordance with one or more aspects of the present disclosure. The downhole tool 700, as shown, represents a dual packer module and may be disposed in a wellbore of a formation F by use of a wireline cable 706. The downhole tool 700 may include an upper packer element 720 and a lower packer element 721. FIG. 7A shows a schematic in which the packer elements 720 and 721 are in a non-inflated and/or non-engaged state. FIG. 7B shows a schematic in which the packer elements 720 and 721 are in an inflated and/or engaged state, whereby a fluid seal is created between the packer elements 720 and 721 and the wellbore wall 704.

The downhole tool 700 may include a selectively operable fluid port 710 configured to allow for fluid communication between the wellbore and a flow line (dashed lines shown in FIG. 7A) of the downhole tool 700. The flow line may pass through the body of the packer elements 720 and 721, and may extend to sample chambers, to other parts of the downhole tool 700 (shown as 705), to other downhole tools, or to the surface, thereby allowing for fluid communication between all aspects of the downhole tools and the surface. The packer elements 720 and 721 may be connected to the fluid port 710 by connecting ends 745. As shown in FIGS. 7A and 7B, the fluid port 710 may be configured to not include a packer element, and the packer elements 720 and 721 may not be located between the fluid port 710 and the connecting ends 745.

As shown in FIG. 7B, the packer elements 720 and 721 may be inflated to create a fluid seal with the wellbore wall 704. Accordingly, an interval 702 may be created. The interval 702 may include the annulus region 703 between the tool body and the wellbore wall 704 and the components of the tool body between the two packer elements 720 and 721. As shown, the interval of FIG. 7B includes the fluid port 710 with the flow line of downhole tool 700 running therethrough and connecting ends 745. The fluid port 710 may be operated from the surface to extract fluid from the sealed interval or may be operated to pump fluid from the flow line into the sealed interval. As shown, the fluid port 710 may be located approximately at the center of the interval 702. However, adapters may be added above and/or below fluid port 710 to simultaneously change the length of the interval and change the relative position of fluid port 710 within the interval.

The downhole tool 700 may be operated and controlled from the surface of the wellsite by a surface unit 701. The wireline cable 706 may enable the downhole tool 700 to be electrically coupled to the surface unit 701, which may include a control panel and/or a monitor (not shown). The surface unit 701 may be configured to provide electrical power to the downhole tool 700, such as to monitor the status and/or activities of the downhole tool 700 and/or other elements disposed downhole. In addition, the surface unit 701 may be configured to control the activities of the downhole tool 700 and other downhole equipment.

Referring to FIGS. 8A and 8B, illustrated are schematics of downhole tools 800 and 801 in accordance with one or more aspects of the present disclosure. Similar to the downhole tool 700, the downhole tools 800 and 801 may each include an upper packer element 820 and a lower packer element 821 and a fluid port 810 on the tool body between the packer elements 820 and 821, with the packer elements 820 and 821 connected to the fluid port 810 by connecting ends 845. However, as shown in FIGS. 8A and 8B, a fluid port adapter 830 or 832, respectively, may be installed over the fluid port 810. The fluid port adapters 830 and 832 may provide the fluid port 810 with fluid communication with a location of the sealed interval different from the location of the fluid port 810. Specifically, inlet/outlet ports 831 and 833 may be provided on the distal ends of the fluid port adapters 830 and 832, respectively. The inlet/outlet ports 831 and 833 may allow for fluid communication between the sealed interval and the fluid port 810. Accordingly, the fluid port 810 may be in fluid communication with a part of the sealed interval not directly adjacent to the fluid port 810. As noted above, this configuration may allow for sampling of fluid that may settle to the bottom of the sealed interval, or may be more buoyant and rise to the top of the sealed interval, allowing for a sampling of a desired fluid at a specific point in the sealed interval. Although the inlet/outlet ports are shown at the extreme lower and upper positions in the sealed interval, respectively, the length of the fluid port adapters 830 and 832 may be modifiable to reach any position in the sealed interval.

Referring to FIG. 9, illustrated is a schematic of a downhole tool 900 in accordance with one or more aspects of the present disclosure. As shown, the downhole tool 900 may include an upper packer element 920 and a lower packer element 921, with connecting ends 945. A fluid port adapter 934 may be inserted between the two packer elements 920 and 921 and connected to the connecting ends 945. The fluid port adapter 934 may be configured to prevent fluid communication between a fluid port 910 and a portion of a flow line above the fluid port adapter 934. The fluid port adapter 934 may include an additional fluid port 911 that may be connected to the portion of the flow line above the fluid port adapter 934. Fluid port 910 may maintain fluid communication with a portion of the flow line below the fluid port adapter 934, such that fluid communication between the interval and portions of the downhole tool 900 below the packer element 921 may be established.

As shown in FIG. 9, a spatial vertical separation may separate the fluid ports 910 and 911. For example, the fluid port 910 may be located approximately fifteen inches (approximately 38 cm) below the fluid port 911. However, the amount of separation between the fluid port 910 and the fluid port 911 may be variable, without an upper and/or lower limit. Because of the spatial vertical separation of the fluid ports 910 and 911, if a fluid in the interval segregates due to gravity, the fluid ports 910 and 911 may be exposed to fluids of different density and/or composition. The fluid ports 910 and 911 may be selectively operable such that fluid may be drawn into and/or pumped from both and/or either of the fluid ports 910 and 911. Accordingly, a more dense fluid may be pumped from fluid port 910 downward, such that the fluid may be communicated to other downhole tools (not shown) and/or the fluid may be analyzed and/or captured for analysis at the surface. Similarly, a less dense fluid may be pumped from the fluid port 911 upward to other tools (not shown) and/or the fluid may be analyzed and/or captured for analysis at the surface. The fluid port adapter 934 may be configured to directly connect multiple fluid ports. Accordingly, more than two fluid ports may be provided in the interval between the two packer elements without deviating from the scope of the present disclosure.

Referring to FIG. 10, illustrated is a schematic of a downhole tool 1000 pursuant to one or more aspects of the present disclosure. As shown, the downhole tool 1000 may include three distinct parts. Specifically, a first fluid sampling unit 1040, a second fluid sampling unit 1041, and a connector or connecting section 1042 may be provided to allow for multiple fluid ports to be present in the interval. Each of the multiple fluid ports may be configured to be in fluid communication with a flow line (now shown) passing through the downhole tool 1000. The first fluid sampling unit 1040 may include a first (upper) packer element 1020 and a first (upper) fluid port 1010 and may be connected to the connecting section 1042 by a connecting end 1045. The second fluid sampling unit 1041 may include a second (lower) packer element 1021 and a second (lower) fluid port 1011 and may be connected to the connecting section 1042 by a connecting end 1045. The connecting section 1042 may be located between the first and second fluid sampling units 1040 and 1041, and may be configured to (removably or permanently) couple the two fluid sampling units 1040 and 1041 to form downhole tool 1000. Connecting portion 1042 may provide a male-male or a female-female connection configured to connect to the connecting ends 1045 of units 1040 and 1041. Additional tools and/or components may be included above the first fluid sampling unit 1040, below the second fluid sampling unit 1041, and/or within the connecting portion 1042 between the packers 1020 and 1021. As shown in FIG. 10, the connecting section 1042 may not include packer elements, and the packer elements 1020 and 1021 may not be located between the connecting section 1042 and the connecting ends 1045.

As illustrated in FIG. 10, connecting portion 1041 may include one or more adapters 1030 that may include a field joint, mandrel, dummy mandrel, threaded connector, and/or other removable and/or permanent connecting device. The adapters 1030 may be plugged or be configured to allow a continuous flow line to pass therethrough. A plug may prevent fluid communication between multiple fluid ports. For example, a plug may prevent fluid communication between fluid port 1010 and fluid port 1011. Connecting portion 1042 may include one or more tool bodies 1035 and/or one or more link segments 1035. Tool body 1035 may include sampling, analysis, collection, and/or any other tools known in the art. Link segments 1035 may merely extend the length of connecting section 1042 without providing additional tools to the connecting section but may include one or more flow lines passing therethrough. More or fewer tool bodies and/or link segments may be employed in the connecting section, or elsewhere on the downhole tool and/or tool string, without deviating from the scope of the present disclosure.

Alternatively, the flow line in downhole tool 1000 may be plugged at any location, including within fluid sampling units 1040 and/or 1041, the connecting portion 1042, other adapters in downhole tool 1000, and/or at other locations in the flow line. For example, if the connecting portion 1042 and/or the adapters 1030 are plugged, a flow line through the downhole tool 1000 may not be continuous, but may include two distinct sections of flow line, one for the first fluid sampling unit 1040 and one for the second fluid sampling unit 1041. As such, continuous fluid communication throughout the entire downhole tool 1000 may be not possible. However, the respective flow lines of the first fluid sampling unit 1040 and the second fluid sampling unit 1041 may allow for fluid communication between the fluid ports 1010 and 1011 and any tools and/or equipment that may be in fluid communication with the fluid ports 1010 and 1011. Although two fluid ports are shown in FIG. 10, more or fewer fluid ports may be provided without deviating from the scope of the present disclosure. The downhole tool 1000 may have a larger than necessary interval created between the packer elements 1020 and 1021. Accordingly, the adapters 1030 may be included to allow for a variable length interval, as shown in FIG. 11.

Referring to FIG. 11, illustrated is a schematic view of a downhole tool 1100 in accordance with one or more aspects of the present disclosure. The downhole tool 1100 may be similar to that shown in FIG. 10, incorporating two fluid sampling units 1140 and 1141. For example, a first fluid sampling unit 1140 may include a first packer element 1120, a first fluid port 1110, and a connecting end 1145, and a second fluid sampling unit 1141 may include a second packer element 1121, a second fluid port 1111, and a connecting end 1145. The two fluid sampling units 1140 and 1141 may be connected by a connecting portion 1142 connected to the connecting ends 1145 of the units 1140 and 1141, respectively. The connecting section 1142 may include one or more adapters 1130 and 1131 and a tool body 1135. The adapters 1130 and 1131 may be of any length such that any desired length of interval may be created, or the tool body 1135 may be of variable lengths to thereby adjust the length of the interval. The tool body 1135 may include sampling, analysis, collection, and/or any other tools known in the art. A flow line may pass continuously through the elements of the downhole tool 1100, and, therefore, all parts of the tool body may be in fluid communication with all other parts of the tool body, or with the surface, as discussed above. Alternatively, a plug and/or valve may be located within the flow line such that the flow line of the first fluid sampling unit 1140 may be selectively and/or permanently independent from the flow line of the second fluid sampling unit 1141. As shown in FIG. 11, the connecting section 1142 may not include packer elements, and the packer elements 1120 and 1121 may not be located between the connecting section 1142 and the connecting ends 1145.

Referring to FIG. 12, illustrated is a schematic view of a downhole tool 1200 in accordance with one or more aspects of the present disclosure. As shown, the connecting portion 1242 may include only a single adapter 1230 and may be connected to units 1240 and 1241 by connecting ends 1245 of the units 1240 and 1241. The units 1240 and 1241 may be fluid sampling units and may include fluid port 1210 and packer element 1220 and fluid port 1211 and packer element 1221, respectively. The two fluid ports 1210 and 1211 may be connected by the adapter 1230, which may allow for a flow line to provide fluid communication to all parts of the downhole tool 1200. Aspects of a tool as shown in FIG. 12 may allow for a smaller interval to be achieved, which may be advantageous in certain environments.

Referring to FIGS. 13 and 14, illustrated are schematic views of apparatus according to one or more aspects of the present disclosure. FIG. 13 shows a schematic of a downhole tool 1300, and FIG. 14 shows a schematic of a downhole tool 1400. The downhole tools 1300 and 1400 may include adapters and packer elements, similar to that described above. The units of downhole tools 1300 and 1400 may be fluid sampling units, and may have connecting ends 1345 and 1445, respectively. For example, the downhole tool 1300 may include a first fluid sampling unit 1340 that may include a first packer element 1320 and a first fluid port 1310 and a second fluid sampling unit 1341 that may include a second packer element 1321 and a second fluid port 1311. The downhole tool 1400 may include a first fluid sampling unit 1440 that may include a first packer element 1420 and a first fluid port 1410, a second fluid sampling unit 1341 that may include a second packer element 1421 and a second fluid port 1411.

The downhole tools 1300 and 1400 may include connecting portions 1342 and 1442, respectively. The connecting portions 1342 and 1442 may include adapters 1330 and 1331 and 1430 and 1431, respectively and/or may include valve systems 1350 and 1450, respectively. The adapters 1330 and 1331 and 1430 and 1431 may be mandrels and/or single unitary mandrels and may include the fluid ports 1310 and 1311 and 1410 and 1411, respectively. The valve systems 1350 and 1450 may allow for control of a flow through flow lines that may be formed through the downhole tools 1300 and 1400, and may be operable by a controller (not shown) located in the downhole tool, on other downhole tools, or on the surface.

As shown, the controllable valve systems 1350 and 1450 may be employed in the connecting portions 1342 and 1442, respectively. The controllable valve systems 1350 and 1450 may allow for control over the flow of fluid within and through a flow line in the downhole tools 1300 and 1400. For example, fluid flowing to and/or from the fluid ports 1310 and 1311 and 1410 and 1411, respectively, and with other downhole tools may be controlled by the controllable valve systems 1350 and 1450. An operator may control the controllable valve systems 1350 and 1450 to allow for pumping and/or extraction of fluid from and/or through any fluid port 1310 and 1311 and 1410 and 1411, respectively, and in any direction (up or down in the flow line). Accordingly, an operator may selectively operate the valve systems 1350 and 1450 to allow for fluid from different positions in the sealed interval to be sent to different locations or instruments in the downhole tools 1300 and 1400, respectively, to the surface, to other intervals or regions in the wellbore, or any combination thereof. One or more valves 1351 and 1451, 1452, and 1453 may be employed in the valve systems 1350 and 1450, respectively. Moreover, one or more of the valves 1351 and 1451, 1452, and 1453 of the valve systems 1350 and 1450 may also include fluid ports, such as shown in FIG. 14 as fluid ports 1412, 1413, and 1414.

As shown in FIG. 13, a single controllable valve 1351 may be provided to control the flow of fluid within the downhole tool 1300. Specifically, the valve 1351 may include a directional valve and may include a pump (not shown). The directional valve may be used to control a direction the fluid is to flow in the flow line of the downhole tool 1300. The pump may be used to pump fluid vertically, against gravity, to provide fluid flow in an upward direction to allow for fluid to be communicated to the surface or to parts of the downhole tool that may be vertically above the fluid ports 1310 and 1311. Alternatively, the pump may be used to pump fluid in a downward direction to allow for fluid to be communicated to parts of the downhole tool that may be vertically below the fluid ports 1310 and 1311.

As shown in FIG. 14, the valve system 1450 may include multiple controllable valves 1451, 1452, 1453. Accordingly, an operator may direct different sections of fluid in different directions and may allow for control over which fluid ports 1410 and 1411 may be used to provide fluid communication between the downhole tool 1400 and the sealed interval. The controllable valves 1451, 1452, 1453 of valve system 1450 may each include one or more fluid ports 1412, 1413, and 1414, thereby allowing more fluid ports to be located within the sealed interval. Although three controllable valves are shown with one fluid port each, any number of controllable valves may be employed and that more than one fluid port may be installed on the controllable valves of the valve system.

Referring to FIG. 15, illustrated is a schematic exploded view of a downhole tool 1500 in accordance with one or more aspects of the present disclosure. Downhole tool 1500, or any of the downhole tools of FIGS. 7-14, may include, for example, a sample side 1560 and a guard side 1562. Sample side 1560 may include a power source 1570, a sample module 1572, a fluid analyzer 1574, a pump out module 1576, a condensate and/or gas analyzer 1578, a hydraulic power source 1580, a subassembly and/or probe module 1582, and/or an upper packer and/or mandrel 1584. A first (or upper) fluid sampling unit in accordance with one or more aspects of the present disclosure may include one or more elements of the sample side 1560. Guard side 1562 may include a lower packer and/or mandrel 1588, a pump out module 1590, and/or a fluid analyzer 1592. A second (or lower) fluid sampling unit in accordance with one or more aspects of the present disclosure may include one or more elements of the guard side 1562. Sample side 1560 and guard side 1562 may be separated by connecting portion 1586. Although downhole tool 1500 is described with specific and limited elements and/or tools, a downhole tool 1500 may include more or fewer and/or different elements and/or tools without deviating from the scope of the present disclosure.

In view of all of the above and the figures, those skilled in the art should readily recognize that the present disclosure introduces an apparatus including a downhole tool configured for conveyance in a wellbore extending into a subterranean formation, the downhole tool including a first unit having a first fluid port configured to provide fluid communication between the first unit and the wellbore, a second unit having a second fluid port configured to provide fluid communication between the second unit and the wellbore, a connector configured to connect a first connecting end of the first unit with a second connecting end of the second unit, wherein the connector does not comprise packer elements, a first packer element mounted on the first unit and not located between the first fluid port and the first connecting end, and a second packer element mounted on the second unit and not located between the second fluid port and the second connecting end. The first unit may include a flow line configured to fluidly couple the first fluid port with the connector. The connector may be configured to fluidly couple the flow line with the second fluid port. The first unit may include a controllable valve configured to control fluid communication between the first fluid port and the flow line. The connector may include a third fluid port configured to provide fluid communication between the flow line and the wellbore. The downhole tool may include a controllable valve configured to control fluid communication between the third fluid port and the flow line. The downhole tool may include a plug configured to prevent fluid communication between the first and second fluid ports. The downhole tool may include a controllable valve configured to control fluid communication between the first and second fluid ports. The downhole tool may include a fluid pumping system configured to pump fluid into at least one of the first and second fluid ports. The downhole tool may include a flow line configured to provide fluid communication between the first fluid port and a location of the wellbore different from a location of the first fluid port. The connector may be configured to provide one of a male-male and a female-female connection. The first unit and the second unit may be interchangeable. The first unit may include a unitary mandrel, and the first fluid port may be located on the unitary mandrel.

The present disclosure also introduces an apparatus including a downhole tool configured for conveyance in a wellbore extending into a subterranean formation, the downhole tool including a first unitary mandrel having a first fluid port configured to provide fluid communication between the first mandrel and the wellbore, a second unitary mandrel having a second fluid port configured to provide fluid communication between the second mandrel and the wellbore, a connector configured to connect a first connecting end of the first mandrel with a second connecting end of the second mandrel, a first packer element mounted on the first mandrel and not located between the first fluid port and the first connecting end, and a second packer element mounted on the second mandrel and not located between the second fluid port and the second connecting end. The first and the second mandrels may be interchangeable. The connector may not include packer elements. The connector may be configured to provide one of a male-male and a female-female connection.

The present disclosure also introduces an apparatus including a downhole tool configured for conveyance in a wellbore extending into a subterranean formation, the downhole tool including first and second units comprising first and second packer elements, respectively, a first connector configured to connect to the first unit, and having a first fluid port configured to provide fluid communication between the first unit and the wellbore and a second connector configured to connect the second unit to the first connector, and having a second fluid port configured to provide fluid communication between the first unit and the wellbore, wherein the first and second connectors do not comprise packer elements. The first unit may further include a flow line fluidly coupled to the first connector. The first connector may further include a controllable valve configured to control fluid communication between the first fluid port and the flow line.

The foregoing outlines feature several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced 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 may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.

The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Claims

1. An apparatus, comprising:

a downhole tool configured for conveyance in a wellbore extending into a subterranean formation, the downhole tool comprising: a first unit having a first fluid port configured to provide fluid communication between the first unit and the wellbore; a second unit having a second fluid port configured to provide fluid communication between the second unit and the wellbore; a connector configured to connect a first connecting end of the first unit with a second connecting end of the second unit, wherein the connector does not comprise packer elements; a first packer element mounted on the first unit and not located between the first fluid port and the first connecting end; and a second packer element mounted on the second unit and not located between the second fluid port and the second connecting end.

2. The apparatus of claim 1 wherein the first unit comprises a flow line configured to fluidly couple the first fluid port with the connector.

3. The apparatus of claim 2 wherein the connector is configured to fluidly couple the flow line with the second fluid port.

4. The apparatus of claim 2 wherein the first unit comprises a controllable valve configured to control fluid communication between the first fluid port and the flow line.

5. The apparatus of claim 2 wherein the connector comprises a third fluid port configured to provide fluid communication between the flow line and the wellbore.

6. The apparatus of claim 5 wherein the downhole tool comprises a controllable valve configured to control fluid communication between the third fluid port and the flow line.

7. The apparatus of claim 1 wherein the downhole tool comprises a plug configured to prevent fluid communication between the first and second fluid ports.

8. The apparatus of claim 1 wherein the downhole tool comprises a controllable valve configured to control fluid communication between the first and second fluid ports.

9. The apparatus of claim 1 wherein the downhole tool comprises a fluid pumping system configured to pump fluid into at least one of the first and second fluid ports.

10. The apparatus of claim 1 wherein the downhole tool comprises a flow line configured to provide fluid communication between the first fluid port and a location of the wellbore different from a location of the first fluid port.

11. The apparatus of claim 1 wherein the connector is configured to provide one of a male-male and a female-female connection.

12. The apparatus of claim 1 wherein the first unit and the second unit are interchangeable.

13. The apparatus of claim 1 wherein the first unit comprises a unitary mandrel, and wherein the first fluid port is located on the unitary mandrel.

14. An apparatus, comprising:

a downhole tool configured for conveyance in a wellbore extending into a subterranean formation, the downhole tool comprising: a first unitary mandrel having a first fluid port configured to provide fluid communication between the first mandrel and the wellbore; a second unitary mandrel having a second fluid port configured to provide fluid communication between the second mandrel and the wellbore; a connector configured to connect a first connecting end of the first mandrel with a second connecting end of the second mandrel; a first packer element mounted on the first mandrel and not located between the first fluid port and the first connecting end; and a second packer element mounted on the second mandrel and not located between the second fluid port and the second connecting end.

15. The apparatus of claim 14 wherein the first and the second mandrels are interchangeable.

16. The apparatus of claim 14 wherein the connector does not comprise packer elements.

17. The apparatus of claim 14 wherein the connector is configured to provide one of a male-male and a female-female connection.

18. An apparatus, comprising:

a downhole tool configured for conveyance in a wellbore extending into a subterranean formation, the downhole tool comprising: first and second units comprising first and second packer elements, respectively; a first connector configured to connect to the first unit, and having a first fluid port configured to provide fluid communication between the first unit and the wellbore; and a second connector configured to connect the second unit to the first connector, and having a second fluid port configured to provide fluid communication between the first unit and the wellbore; wherein the first and second connectors do not comprise packer elements.

19. The apparatus of claim 18 wherein the first unit further comprises a flow line fluidly coupled to the first connector.

20. The apparatus of claim 19 wherein the first connector further comprises a controllable valve configured to control fluid communication between the first fluid port and the flow line.