APPARATUS AND METHOD FOR COLLECTING A DOWNHOLE FLUID

Abstract

A method and apparatus for collecting a downhole fluid are disclosed. A method includes receiving a downhole fluid into a downhole sub from a first borehole wall portion adjacent a formation of interest and expelling at least a portion of the received downhole fluid from the downhole sub to a second borehole wall portion, wherein substantially all of the expelled downhole fluid enters the second borehole wall portion. An apparatus includes a downhole sub, a formation sampling member coupled to the downhole sub for collecting the downhole fluid from a first borehole wall portion adjacent a formation of interest, a sample expulsion member coupled to the downhole sub for expelling at least a portion of the collected downhole fluid from the downhole sub to a second borehole wall portion, wherein substantially all of the expelled downhole fluid enters the second borehole wall portion.

Description

BACKGROUND

Technical Field

The present disclosure generally relates to apparatuses and methods for evaluating formations traversed by a well borehole and in particular to formation sampling and testing.

Background Information

Formation sampling and testing tools have been used in the oil and gas industry for collecting formation samples, for monitoring formation parameters such as pressure along a well borehole, and for predicting performance of reservoirs around the borehole. Such formation sampling and testing tools typically include an elastomer packer or pad that is pressed against a borehole wall portion to form an isolated zone from which formation samples are collected. Information that helps in determining the viability of the formation for producing hydrocarbons and in determining drilling operation parameters may then be acquired by evaluating the formation samples.

Information about the subterranean formations traversed by the borehole may be obtained by any number of techniques. Techniques used to obtain formation information include obtaining one or more downhole fluid samples produced from the subterranean formations. Downhole fluids, as used herein include any one or any combination of drilling fluids, return fluids, connate formation fluids, and formation fluids that may be contaminated by materials and fluids such as mud filtrates, drilling fluids and return fluids. Downhole fluid samples are often retrieved from the borehole and tested in a rig-site or remote laboratory to determine properties of the fluid samples, which properties are used to estimate formation properties. Modern fluid sampling also includes various downhole tests to estimate fluid properties while the fluid sample is downhole.

Some formations produce hazardous fluids, and local governmental regulations may greatly control and restrict the amount of formation fluids that are introduced into the well borehole to reduce the risk of exposing the surface environment and personnel to these hazardous fluids. This is the case even when it is necessary to retrieve connate formation samples from formations that produce hazardous downhole fluids. It is difficult to retrieve connate formation samples from these hazardous fluid producing formations, because borehole fluids and filtrates often contaminate the formation samples. One obstacle is that cleanup processes used to remove borehole contaminants from a fluid sample to obtain a connate fluid sample substantially free of borehole contaminants usually results in ejecting large amounts of formation fluid into the borehole. Thus, the hazardous formation fluids are produced into the return fluid posing environmental threats and hazards to personnel at the surface.

SUMMARY

The following presents a general summary of several aspects of the disclosure in order to provide a basic understanding of at least some aspects of the disclosure. This summary is not an extensive overview of the disclosure. It is not intended to identify key or critical elements of the disclosure or to delineate the scope of the claims. The following summary merely presents some concepts of the disclosure in a general form as a prelude to the more detailed description that follows.

A method for collecting a downhole fluid includes receiving a downhole fluid into a downhole sub from a first borehole wall portion adjacent a formation of interest and expelling at least a portion of the received downhole fluid from the downhole sub to a second borehole wall portion, wherein substantially all of the expelled downhole fluid enters the second borehole wall portion.

Another method aspect for collecting a downhole fluid includes conveying a downhole sub in a borehole, the downhole sub including a fluid sampling tool. A first borehole wall portion adjacent a formation of interest is sealed using a first seal coupled to the fluid sampling tool and a second borehole wall portion is sealed using a second seal coupled to the fluid sampling tool. A first fluid path is established with the first borehole wall portion and the tool. A second fluid path is established with the second borehole wall portion and the tool. The method further includes receiving the downhole fluid into the fluid sampling tool using the first fluid path, flowing the received downhole fluid through the tool during a cleanup process, estimating a fluid contamination level during the cleanup process, and expelling at least a portion of the received downhole fluid from the tool using the second fluid path during the cleanup process to remove some or all borehole contaminants from the received downhole fluid until fluid flowing through the tool is a substantially contamination free connate formation fluid. The substantially contamination free connate formation fluid may be stored in a fluid sample chamber.

An apparatus includes a downhole sub, a formation sampling member coupled to the downhole sub for collecting the downhole fluid from a first borehole wall portion adjacent a formation of interest, a sample expulsion member coupled to the downhole sub for expelling at least a portion of the collected downhole fluid from the downhole sub to a second borehole wall portion, wherein substantially all of the expelled downhole fluid enters the second borehole wall portion.

BRIEF DESCRIPTION OF THE DRAWINGS

For detailed understanding of the present disclosure, references should be made to the following detailed description of the several embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:

FIG. 1 schematically illustrates a non-limiting example of a well logging system in a wireline arrangement according to several non-limiting embodiments of the disclosure;

FIG. 2 illustrates a non-limiting example of extendable probes useful in several embodiments of the disclosure;

FIG. 3 illustrates a non-limiting example of a straddle packer arrangement useful in several embodiments of the disclosure;

FIG. 4 illustrates a non-limiting example of a fluid sample container suitable for operation as a flush-through sample container; and

FIG. 5 illustrates an exemplary fluid sample container including one or more devices for controlling pressure within the container during transport.

DESCRIPTION OF EXEMPLARY EMBODIMENTS

FIG. 1 schematically illustrates a non-limiting example of a well logging system 100 in a wireline arrangement according to several non-limiting embodiments of the disclosure. The exemplary logging system 100 includes a downhole sub 102 shown disposed in a borehole 104 and supported by a wireline cable 106. The exemplary downhole sub 102 may include one or more centralizers 108, 110 for centralizing the downhole sub 102 in the borehole 104. The cable 106 may be supported by a sheave wheel 112 disposed in a drilling rig 114. The cable 106 may be wound on a drum 116, shown here mounted on a truck 118, for lowering or raising the downhole sub 102 in the borehole. The cable 106 may comprise a multi-strand cable having electrical conductors for carrying electrical signals and power from the surface to the downhole sub 102 and for transmitting information to and from the downhole sub 102. The downhole sub 102 may send information to and receive information from the surface for processing and/or for executing commands. A surface transceiver 120 and a controller 122 may be located on the truck 118 or at any suitable surface location. The exemplary downhole sub 102 communicates with the surface controller 122 via the surface transceiver 120 and a downhole transceiver 124.

The exemplary wireline FIG. 1 operates as a carrier, but any carrier is considered within the scope of the disclosure. The term “carrier” as used herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member. Exemplary non-limiting carriers include drill strings of the coiled tube type, of the jointed pipe type and any combination or portion thereof. Other carrier examples include casing pipes, wirelines, wireline sondes, slickline sondes, downhole subs, BHA's, drill string inserts, modules, internal housings and substrate portions thereof.

In the non-limiting embodiment of FIG. 1, the downhole sub 102 includes a downhole evaluation tool 126, and the downhole evaluation tool 126 may include an assembly of several tool segments that are joined end-to-end by threaded sleeves or mutual compression unions 128. An assembly of tool segments suitable for the present disclosure may include an arrangement as shown in FIG. 1. The exemplary arrangement includes the transceiver 124 discussed above, and a downhole controller 130 is shown below the transceiver 124. The downhole controller 130 may further include a processor and memory for processing information and for executing commands used for controlling aspects of the downhole sub 102. A power unit 132 may be coupled below the controller 130. The power unit 132 may include one or more of a hydraulic power unit, an electrical power unit and an electromechanical power unit. A formation sampling tool 134 is shown coupled to the downhole evaluation tool 126 below the power unit 132.

The exemplary formation sampling tool 134 shown in FIG. 1 includes a formation sampling member 136 and a sample expulsion member 138. The formation sampling member 136 may be extendable as shown in this example or the formation sampling member 136 may be a tool portion having a port for receiving a formation sample. Likewise, the sample expulsion member 138 may be extendable as shown in this example or the sample expulsion member 138 may be a tool portion having a port for expelling a formation sample from the tool. The exemplary formation sampling tool 134 may be configured for acquiring and/or extracting a formation core sample, a formation fluid sample, formation images, nuclear information, electromagnetic information, and/or other downhole samples.

Referring to FIGS. 1, 2 and 3, several non-limiting embodiments may be configured with the formation sampling tool 134 operable as a fluid sampling tool. In these embodiments, the formation sampling member may include an extendable probe having a sealing pad 200 for isolating a portion of the well borehole. The fluid expulsion member 138 may also include an extendable probe having a sealing pad 200 as depicted in FIG. 2. Other exemplary arrangements may use straddle packers 300 as depicted in FIG. 3 for isolating borehole portions for the respective formation sampling member 136 and fluid expulsion member 138. Combinations of extendable pad seals and straddle packers are also within the scope of the disclosure. A fluid pump 140 may be placed in fluid communication with the formation sampling member 136 included with the formation sampling tool 134 for collecting fluid samples. The fluid pump 140 may be a single pump or may include one pump for line purging and a smaller displacement pump for collecting samples and for quantitatively monitoring fluid received by the downhole evaluation tool via the formation sampling tool 134. The fluid pump 140 may be a variable rate pump or a constant rate pump.

One or more flush-through fluid sample containers 142 may be included below the fluid pump 140 and above the sample expulsion member 138. In several examples, the fluid sample containers 142 are individually or collectively detachable from the downhole evaluation tool formation sampling tool 134. Further details of several exemplary flush-through fluid sample containers will be provided below with reference to FIGS. 4-5.

FIG. 4 illustrates a non-limiting example of fluid sample container 400 suitable for operation as a flush-through sample container according to one or more embodiments described above and shown in FIG. 1 at reference numeral 142. The exemplary fluid sample container 400 may be used in a wireline arrangement, in a while-drilling drilling arrangement, a slickline arrangement or by using any suitable carrier for conveying the fluid sample container 400 in a well borehole. The exemplary embodiment of FIG. 4 is shown detachably mounted in a downhole sub 102.

The exemplary fluid sample containe 400 shown in FIG. 4 includes an elongated body 402 having an internal cavity 404 for receiving fluid samples 406. The elongated body 402 portion of the exemplary fluid sample container 400 includes a first end 408 and a second end 410 axially displaced from the first end. The elongated body 402 has a first opening 412 in the first end for receiving the fluid 406 into the internal cavity 404, and a second opening 414 in the second end 410 for expelling at least a portion of the fluid 406 from the internal cavity 404. The fluid sample container 400 of this non-limiting embodiment includes a fluid flow control device 416 proximate the second end 410 of the body 402 and coupled to the downhole sub for controlling fluid expulsion from the internal cavity 404. The fluid flow control device 416 shown may be a controlled valve or any suitable fluid flow control device that is controllable to control fluid expulsion from the second opening 414 during fluid sampling and may be operable to cease fluid expulsion when a predetermined parameter is met for the downhole fluid expelled from the fluid container 400.

Additional fluid control devices 416 are shown in the exemplary embodiment of FIG. 4 coupled to the downhole sub input flow line 420 and within the container 400 proximate the body first end 408 to control fluid flow to and within the first end. The first end fluid control devices may be substantially similar to the fluid control devices 416 proximate the second end 410, but the fluid control devices 416 may be of different types without departing from the scope of the disclosure.

The exemplary embodiment shown in FIG. 4 includes a flow line connector 418 connected to an input flow line 420 at the body first end 408 for allowing fluid flow into the internal cavity 404. A similar flow line connector 418 and flow control device 416 are shown coupled to an output flow line 422 at the body second end 410 for allowing fluid expulsion from the internal cavity 404. The input flow line 420 and the output flow line 422 in the example shown here are flow line portions of the downhole sub 102 that are in fluid communication with the internal cavity 404 of the formation sample container 400.

The fluid sample container 400 may be detachable from the downhole sub 102 using detachable flow line connectors 418 and one or more detachable mounting members 424 that couple the fluid sample container body 402 to the downhole sub 102. The downhole sub 102 may include a pump 140 for conveying fluid through a fluid flow control device 416, which may be a valve controllable downhole using command signals. The fluid flow control device 416 is in communication with the internal cavity 404.

The exemplary fluid sample container 400 may further include a check value 426 as shown coupled to the input flow line connector 418 and a similar check valve 426 coupled to the output flow line connector 418 to help ensure fluid flows through the fluid sample container 400 in one direction during a downhole sample cleanup process.

The non-limiting embodiment of FIG. 4 may further include a fluid evaluation module 428. In one or more embodiments, the fluid evaluation module 428 may be in fluid communication with the output flow line 422 for estimating fluid content of fluid expelled from the internal cavity 404. In one or more embodiments, the fluid evaluation module 428 may be in fluid communication with the input flow line 420 for estimating fluid content of fluid entering the internal cavity 404. In one or more embodiments, a fluid evaluation module 428 may be in fluid communication with both the input flow line 420 and the output flow line 422 for estimating fluid content of fluid entering and exiting the internal cavity 404. The fluid evaluation module may be a single module as shown or may be implemented using two or more modules.

The fluid evaluation module 428 may include any number of fluid measurement devices for estimating fluid characteristics of the fluid 406 entering or leaving the internal cavity 404. The fluid evaluation module 428 may be arranged to estimate optical characteristics, electrical characteristics, physical characteristics and any combination of characteristics of the fluid 406. For example, some test devices may be in fluid contact with fluid flowing in the fluid evaluation module, some devices may be in optical communication, some devices may be in acoustic communication, some devices may be in physical contact with the fluid, and still others may be in pressure and/or thermal communication with the fluid.

Optical characteristics may be estimated using a downhole fluorescence test device, a reflectometer, a spectrometer, or any combination thereof. Physical characteristics of the fluid may be estimated using a viscometer, a pressure sensor, a temperature sensor, fluid density transducer, or any combination thereof. Electrical characteristics of the fluid 406 may be estimated using resistivity measurement devices, capacitance and dielectric constant measurement devices, or combinations thereof. Other devices may be included with the fluid evaluation module 428 for estimating fluid chemical properties and compositional properties. Exemplary devices include, but are not limited to, a gas chromatograph, a pH test device, a salinity test device, a CO2 test device, an H2S test device, a device for determining wax and asphaltene components, a device for determining metal content, (mercury or other metal), a device for determining acidity of the fluid, or any combination thereof.

In one or more embodiments, the internal cavity 404 is defined by a smooth curvilinear surface 430 within the body 402. The surface 430 may be selected based on the desired cavity volume, overall size of the body and on fluid flow characteristics. In the exemplary embodiment of FIG. 4, the internal cavity 404 has a substantially oval cross section along a longitudinal axis. In one or more embodiments, the internal cavity 404 may be spherical with a substantially circular cross section. In one or more embodiments, the internal cavity 404 may have a cylindrical center portion with flat end portions, hemispherical end portions, conical end portions, or any other end portion shape that provides relatively free fluid flow within the internal cavity 404. A surface treatment that reduces fluid adhesion may be used to further reduce sticking and resistance in the fluid flow within the internal cavity 404. Exemplary surface treatments include, but are not limited to, polishing, coatings, laminates, inserts and combinations thereof.

Turning now to FIG. 5, and exemplary fluid sample container 500 may further include one or more devices for controlling pressure within the container 500 during transport. The non-limiting embodiment shown in FIG. 5 is coupled to a downhole sub 102 and includes a substantially cylindrical internal cavity 504. Many of the items in FIG. 5 may be substantially lo similar to the like-numbered items describe above and shown in FIG. 4. For brevity, the following description will focus more on the additional features shown in FIG. 5.

The exemplary fluid sample container 500 includes and elongated body 502 having an internal cavity 504 for receiving fluid samples 506. The elongated body 502 portion of the exemplary fluid sample container 500 includes a first end 508 and a second end 510 axially displaced from the first end. The elongated body 502 has a first opening 512 in the first end 508 for receiving the fluid into the internal cavity 504 from the formation sampling member 136. A second opening 514 in the second end 510 may be used for expelling at least a portion of the fluid 506 from the internal cavity 504 through the fluid expulsion member 138. The fluid sample container 500 of this non-limiting embodiment includes a pressure control device 516 for controlling pressure of the fluid sample 506. The pressure control device 516 provides a flow path via a check valve 522 for fluid 506 flowing through the internal cavity 504 and allows for substantially unrestricted flow during the cleanup process and expulsion of fluid from the internal cavity 504 via the expulsion member 138. The pressure control device 516 in one or more non-limiting embodiments includes a piston 526 that is movably disposed within the cavity 504. One or more O-rings 518 provide a fluid and pressure seal between the piston 526 and cavity wall 530. The check valve 522 is positioned within the piston 526 to provide a flow path through the piston 526 to the opening 514 in the second end 510.

The piston 526 is shown positioned toward the second end 510 with the sample 506 shown with an arrow to indicate the direction of flow through the container 500. The check valve 522 prevents flow in the opposite direction. In this manner, the fluid flow through the internal cavity is substantially free flowing during sample cleanup.

The pressure control device 516 may be actuated using a device controller 520. In one or more embodiments, the device controller 520 may be a pump substantially similar to the pump 140 described above and shown in FIG. 1. In one or more embodiments, the pump 140 may be used as the controller for the pressure control device 516. A gas supply 524 is shown in communication with one end of the piston 526 and with the device controller 520. In one or more embodiments, the gas supply may include a pressurized inert gas such as nitrogen. When actuated, the device controller may be used to add pressure to the gas supply and/or to urge gas toward the piston 526. When pressurized, the piston tends to move toward the first end 508, thereby decreasing the volume in the cavity 504 and/or increasing the pressure within the cavity 504 when one or more of the inflow and outflow fluid control devices 416 are actuated to cease fluid flow. In this manner, the fluid 506 may be maintained at a predetermined pressure once a fluid sample is collected in the internal cavity 504. For example, the fluid 506 may be maintained above its bubble point pressure for transport to the surface.

Several non-limiting operational embodiments for formation sampling will now be described with reference to FIGS. 1 through 5. In one or more embodiments a downhole sub 102 may be conveyed in a well borehole to a formation of interest. A portion of the borehole is isolated using straddle packers, a pad seal disposed on the end of an extendable probe or by using a combination of packers and extendable probe to create an isolated zone. Fluid communication is established between the formation of interest and the downhole sub by exposing a tool port to the isolated zone. In some embodiments, formation pressure may be sufficient to flow fluid from the formation into the tool. In one or more embodiments, a pump 140 or other flow controller may be used to urge fluid into the downhole sub.

Fluid flow into the downhole sub may be maintained in a substantially continuous manner to perform a cleanup process for removing borehole contaminants from the downhole fluid entering the downhole sub. The sample cleanup process may include initially expelling fluid from the downhole sub while the pump or formation pressure urges fluid through the downhole sub. In one or more embodiments, the fluid is monitored for content properties during the cleanup process to estimate a cleanliness level of the fluid flowing within the tool. In one or more embodiments, fluid expulsion is accomplished by reinjecting the expelled fluid into the formation proximate the downhole sub to limit or prevent the fluid from entering the borehole annulus. In one or more embodiments, the fluid is injected into the formation using an extendable expulsion member that is extended to establish fluid communication with the formation. The fluid expulsion may be halted when the fluid within the tool is estimated to be substantially free of contaminants.

In one or more embodiments, fluid samples may be contained within the tool using an internal fluid sample container 400, 500. In one or more embodiments, the fluid cleanup process may include urging the fluid received in the tool through a first end of the fluid sample container and expelling the fluid from a second end of the fluid sample container. Once the estimations show that the fluid within the fluid sample container are substantially free of contaminants, the second container end flow path may be closed using a sub-carried valve 416 that is in fluid communication with the output flow line 422.

The pump 140 may be used to increase the pressure in the container internal cavity 404, 504 to a desired pressure. Once the pressure within the internal cavity reaches the desired pressure, then the pump may be halted and a second sub-carried valve 416 that is in fluid communication with the input flow line 420 may be actuated to close the flow path into the internal cavity 404, 504. In this manner, the fluid sample 406, 506 is sealed within a volume defined between the two sub-carried valves 416.

Pressure within the internal cavity may be controlled after sample collection and during transport using a pressure control device. Fluid may flow through the pressure control device during the cleanup process and a check valve may be used to allow fluid flow in only one direction through the pressure control device. An inert gas may be used to move a piston within the internal cavity to control pressure.

In one or more embodiments, the fluid sample container 400, 500 may be transported to a surface location and removed from the downhole sub without losing fluid containment within the internal cavity 404, 504. Surface operations may include actuating the first end and second end fluid control devices 416 within the container body 402, 502 to seal the respective first end and second end portions of the internal cavity 404, 504. The fluid sample 20 container 400, 500 may then be disconnected from the downhole sub 102 by disconnecting the detachable couplings 424 and the flow line connectors 418.

The sample container internal cavity 404, 504 may be flushed of contaminants and/or connate fluids without leaving substantial residue within the internal cavity. The pump 140 may generate a fluid flow through the cavity. In some embodiments, the cavity 404, 504 includes a curvilinear wall 430, 530 that reduces fluid sticking within the cavity. The wall 430, 530 may further include a surface treatment that further reduces fluid resistance and may be used to reduce sample sticking along the wall 430, 530.

Fluid initially urged into the downhole sub 102 may include one or more contaminants such as borehole fluid and filtrates. Undesirable fluid sample components such as the above-noted contaminants may be cleaned from the fluid entering the downhole evaluation tool 126 by pumping the fluid into the tool and then expelling the fluid through the sample expulsion member 138 until the fluid entering the tool is substantially free of the undesirable contaminants.

In one or more embodiments, pumping and expulsion is performed for a period of time without separate content monitoring with the period of time selected to establish substantially contaminant-free connate fluid flow in the tool. The fluid sample expulsion may be halted on or after completion of the time-based pumping. In one or more embodiments, fluid flowing in the tool is monitored using a downhole tester to estimate fluid content in substantially real-time. The fluid sample expulsion may be halted on or after the content estimate establishes that the fluid flowing in the tool is substantially contaminant-free connate fluid.

One or more operational embodiments address fluid expulsion where environmental regulations, safety concerns or other factors make it desirable to reduce or avoid introducing produced formation fluid to the well borehole. Fluid communication may be established between the sample expulsion member 138 and the formation proximate the sample expulsion member. In this manner, fluid expelled from the tool may be directly injected into the formation with leakage into the well borehole being reduced to levels in compliance with the applicable regulations or to levels that mitigate the safety hazards or that otherwise meet the selected leakage standards set for the particular sampling operation. Formation fluid samples that are substantially free of contaminants may be brought to the surface for testing on-site or in a laboratory environment using the flush through sample container 142.

The present disclosure is to be taken as illustrative rather than as limiting the scope or nature of the claims below. Numerous modifications and variations will become apparent to those skilled in the art after studying the disclosure, including use of equivalent functional and/or structural substitutes for elements described herein, use of equivalent functional couplings for couplings described herein, and/or use of equivalent functional actions for actions described herein. Such insubstantial variations are to be considered within the scope of the claims below.

Claims

1. A method for collecting a downhole fluid, the method comprising:

receiving the downhole fluid into a downhole sub from a first borehole wall portion adjacent a formation of interest; and

expelling at least a portion of the received downhole fluid from the downhole sub to a second borehole wall portion, wherein substantially all of the expelled downhole fluid enters the second borehole wall portion.

2. A method according to claim 1, wherein the first borehole wall portion includes an isolated zone sealed using one or more of expanding a packer to contact the borehole wall and extending a probe having a sealing pad to contact the borehole wall.

3. A method according to claim 1, wherein the second borehole wall portion includes an isolated zone sealed using one or more of expanding a packer to contact the borehole wall and extending a probe having a sealing pad to contact the borehole wall.

4. A method according to claim 1, wherein receiving the downhole fluid into a downhole sub includes using a pump to lower fluid pressure within the first flow path.

5. A method according to claim 1, wherein expelling at least a portion of the received downhole fluid includes injecting the expelled downhole fluid into the formation of interest.

6. A method according to claim 1, wherein expelling at least a portion of the received downhole fluid includes injecting the expelled downhole fluid into a formation that is proximate the formation of interest.

7. A method according to claim 1 further comprising estimating a property of the downhole fluid as the downhole fluid flows through the downhole sub.

8. A method according to claim 7, wherein estimating a property of the downhole fluid includes estimating a contamination level.

9. A method according to claim 8, wherein expelling at least a portion of the received downhole fluid includes expelling the received downhole fluid until the estimated contamination level reached a predetermined level of contamination.

10. A method according to claim 1 further comprising storing at least a portion of the received downhole fluid in a fluid sample container.

11. A method for collecting a downhole fluid, the method comprising:

conveying a downhole sub in a borehole, the downhole sub including a fluid sampling tool;

sealing a first borehole wall portion adjacent a formation of interest using a first seal coupled to the fluid sampling tool;

sealing a second borehole wall portion using a second seal coupled to the fluid sampling tool;

establishing a first fluid path with the first borehole wall portion and the tool;

establishing a second fluid path with the second borehole wall portion and the tool;

receiving the downhole fluid into the fluid sampling tool using the first fluid path;

flowing the received downhole fluid through the tool during a cleanup process;

estimating a fluid contamination level during the cleanup process;

expelling at least a portion of the received downhole fluid from the tool using the second fluid path during the cleanup process to remove some or all borehole contaminants from the received downhole fluid until fluid flowing through the tool is a substantially contamination free connate formation fluid; and

storing the substantially contamination free connate formation fluid in a fluid sample chamber.

12. An apparatus for collecting a downhole fluid, the apparatus comprising:

a downhole sub;

a formation sampling member coupled to the downhole sub for collecting the downhole fluid from a first borehole wall portion adjacent a formation of interest; and

a sample expulsion member coupled to the downhole sub for expelling at least a portion of the collected downhole fluid from the downhole sub to a second borehole wall portion, wherein substantially all of the expelled downhole fluid enters the second borehole wall portion.

13. An apparatus according to claim 12 further comprising one or more of a packer and a probe having a sealing pad to contact the borehole wall for isolating the first borehole wall portion.

14. An apparatus according to claim 12 further comprising one or more of a packer and a probe having a sealing pad to contact the borehole wall for isolating the second borehole wall portion.

15. An apparatus according to claim 12 further comprising a pump for flowing the downhole fluid through the downhole sub.

16. An apparatus according to claim 12, wherein the sample expulsion member includes a port positioned for injecting the expelled downhole fluid into the formation of interest.

17. An apparatus according to claim 12, wherein the sample expulsion member includes a port positioned for injecting the expelled downhole fluid into a formation that is proximate the formation of interest.

18. An apparatus according to claim 12 further comprising a fluid evaluation module for estimating a property of the downhole fluid as the downhole fluid flows through the downhole sub.

19. An apparatus according to claim 18, wherein the fluid evaluation module is operable for estimating a contamination level of the downhole fluid.

20. An apparatus according to claim 12 further comprising a fluid sample container for storing at least a portion of the received downhole fluid.