MINIMIZATION OF CONTAMINANTS IN A SAMPLE CHAMBER

Abstract

A formation testing apparatus and method for obtaining samples with lower levels of contaminants is provided. Such a method can remove contaminants from at fluid sample, and can include the steps of obtaining fluid, from a formation and passing a first quantity of the fluid through a sample flow line. A connection between the sample flow line and a sample chamber can he opened, and a first portion of the first quantity of the fluid can be drawn into the sample chamber via a floating piston. The first portion can be forced out of the sample chamber, and this process can be repeated until sufficient contaminants have been removed. Finally, a second portion of the first quantity of the fluid can be drawn into the sample chamber as the fluid sample.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

None.

FIELD OF THE INVENTION

Aspects relate to downhole drilling. More specifically, aspects relate to minimization of contaminants in sample chambers in downhole tools.

BACKGROUND INFORMATION

Wellbores are drilled, to locate and produce hydrocarbons. A downhole drilling tool with a bit at an end thereof is advanced into the ground to form a wellbore. As the drilling tool is advanced, a drilling mud is pumped through the drilling toot and out the drill hit to cool the drilling tool and carry away cuttings. The fluid exits the drill bit and flows hack up to the surface for recirculation through the tool. The drilling mud is also used to form a mudcake to line the wellbore.

During the drilling operation, various evaluations of the formations penetrated by the wellbore can be performed. In some cases, the drilling tool may be provided with devices to test and/or sample the surrounding formation. In some cases, the drilling tool ma be removed and a wireline tool may be deployed into the wellbore to test and/or sample the formation. In other cases, the drilling tool may be used to perform the testing or sampling. These samples or tests may be used, for example, to locate valuable hydrocarbons. Examples of drilling tools with testing/sampling capabilities are provided in U.S. Pat. Nos. 6,871,713, 7,234,521 and 7,114,562, the entireties of which are incorporated herein by reference.

Formation evaluation often requires that fluid from the formation he drawn into the downhole tool for testing and/or sampling. Various devices, such as probes, are extended from the downhole tool to establish fluid communication with the formation surrounding the wellbore and to draw fluid into the downhole tool. A typical probe is a circular element extended from the downhole tool and positioned against the sidewall of the wellbore. A rubber packer at the end of the probe is used to create a seal with the wellbore sidewall. Another device used to form a seal with the wellbore sidewall is referred to as a dual packer. With a dual packer, two elastomeric rings expand radially about the tool to isolate a portion of the wellbore therebetween. The rings firm a seal with the wellbore wall and permit fluid to be drawn into the isolated portion of the wellbore and into an inlet in the downhole tool.

The mudcake lining the wellbore is often useful in assisting the probe and/or dual packers in making the seal with the wellbore wall. Once the seal is made, fluid from the formation is drawn into the downhole tool through an inlet by lowering the pressure in the downhole tool. Examples of probes and/or packers used in downhole tools are described in U.S. Pat. Nos. 6,301,959; 4,860,581; 4,936,139; 6,585,045; 6,609,568; 6,719,049 and 6,964,301, the entireties of which are incorporated herein by reference.

The collection and sampling of underground fluids contained in subsurface formations is well known. In the petroleum exploration and recovery industries, for example, samples of formation fluids are collected and analyzed for various purposes, such as to determine the existence, composition and/or producibility of subsurface hydrocarbon fluid reservoirs. This aspect of the exploration and recovery process can be crucial in developing drilling strategies, and can impact significant financial expenditures and/or savings.

To conduct valid fluid analysis, the fluid obtained from the subsurface formation should possess sufficient purity, or be virgin fluid, to adequately represent the fluid contained in the formation. As used within the scope of the present disclosure, the terms “virgin fluid,” “acceptable virgin fluid” and variations thereof mean subsurface fluid that is pure, pristine, connate, uncontaminated or otherwise considered in the fluid sampling and analysis field to be sufficiently or acceptably representative of a given formation for valid hydrocarbon sampling and/or evaluation.

Various challenges may arise in the process of obtaining virgin fluid from subsurface formations. Again with reference to the petroleum-related industries, for example, the earth around the borehole from which fluid samples are sought typically contains contaminates, such as filtrate from the mud utilized in drilling the borehole. This material often contaminates the virgin fluid as it passes through the borehole, resulting in fluid that is generally unacceptable for hydrocarbon fluid sampling and/or evaluation. Such fluid is referred to herein as “contaminated fluid.” Because fluid is sampled through the borehole, mudcake, cement and/or other layers, it is difficult to avoid contamination of the fluid sample as it flows from the formation and into a downhole tool during sampling. A challenge thus lies in minimizing the contamination of the virgin fluid during fluid extraction from the formation.

FIG. 1 depicts a subsurface formation 102 penetrated by a wellbore 104. A layer of mud cake 106 lines a sidewall 108 of the wellbore 104. Due to invasion of mud filtrate into the formation during drilling, the wellbore is surrounded by a cylindrical layer known as the invaded zone 110 containing contaminated fluid 112 that may or may not be mixed with virgin fluid. Beyond the sidewall of the wellbore and surrounding contaminated fluid, virgin fluid 114 is located in the formation 102. As shown in FIG. 1, contaminates tend to be located near the wellbore wall in the invaded zone 110.

FIG. 2 shows the typical flow patterns of the formation fluid as it passes from subsurface formation 102 into a downhole tool 202. The downhole tool 202 is positioned adjacent the formation and a probe 204 is extended from the downhole tool through the mudcake 106 to the sidewall 108 of the wellbore 104. The probe 204 is placed in fluid communication with the formation 102 so that formation fluid may be passed into the downhole tool 202. Initially, as shown in FIG. 1, the invaded zone 110 surrounds the sidewall 108 and contains contamination. As fluid initially passes into the probe 204, the contaminated fluid 112 from the invaded zone 110 is drawn into the probe with the fluid thereby generating fluid unsuitable for sampling. However, as shown in FIG. 2, after a certain amount of fluid passes through the probe 204, the virgin fluid 114 breaks through and begins entering the probe.

Formation evaluation is typically performed on fluids drawn into the downhole tool. Techniques currently exist for performing various measurements, pretests and/or sample collection of fluids that enter the downhole tool. Various methods and devices have been proposed for obtaining subsurface fluids for sampling and evaluation. For example, U.S. Pat. Nos. 6,230,557, 6,223,822, 4,416,152, and 3,611,799, and PCT Patent Application Publication No. WO 96/30628, the entireties of which are incorporated herein by reference, describe certain probes and related techniques to improve sampling. However, it has been discovered that when the formation fluid passes into the downhole tool, various contaminants, such as wellbore fluids and/or drilling mud, may enter the tool with the formation fluids. These contaminates may affect the quality of measurements and/or samples of the formation fluids. Moreover, contamination may cause costly delays in the wellbore operations by requiring additional time for more testing and/or sampling. Additionally, such problems may yield false results that are erroneous and/or unusable. Other techniques have been developed to separate virgin fluids during sampling. For example, U.S. Pat. No. 6,301,959, the entirety of which is incorporated herein by reference, discloses a sampling probe with two hydraulic lines to recover formation fluids from two zones in the borehole. In this patent, borehole fluids are drawn into a guard zone separate from fluids drawn into a probe zone. Despite such advances in sampling, there remains a need to develop techniques for fluid sampling to optimize the quality of the sample and efficiency of the sampling process,

To increase sample quality, it is desirable that the formation fluid entering into the downhole tool be sufficiently “clean' or “virgin” for valid testing. In other words, the formation fluid should have little or no contamination. Attempts have been made to eliminate contaminates from entering the downhole tool with the formation fluid. For example, as depicted in U.S. Pat. No. 4,951,749, filters have been positioned in probes to block contaminates from entering the downhole tool with the formation fluid. Additionally, as shown in U.S. Pat. No. 6,301,959, a probe is provided with a guard ring to divert contaminated fluids away from clean fluid as it enters the probe. The entireties of both of these are incorporated herein by reference.

Techniques have also been developed to evaluate fluid passing through the tool to determine contamination levels. In some cases, techniques and mathematical models have been developed for predicting contamination for a merged flowline. See, for example, PCT Patent Application No. WO 2005065277 and PCT Patent Application No. 00/50576, the entireties of which are hereby incorporated by reference. Techniques for predicting contamination levels and determining cleanup times are described, in P. S. Hammond, “One or Two Phased Flow During fluid Sampling by a Wireline Tool.” Transport in Porous Media, Vol. 6, p. 299-330 (1991), the entirety of which is hereby incorporated by reference. Hammond describes a semi-empirical technique for estimating contamination levels and cleanup time of fluid passing into a downhole tool through a single flowline.

Despite the existence of techniques for performing formation evaluation, conventional systems fail to adequately mitigate the problem of contamination.

SUMMARY

The following presents a simplified summary of the innovation in order to provide a basic understanding of some aspects of the innovation. This summary is not an extensive overview of the innovation. It is not intended, to identify key/critical elements of the innovation or to delineate the scope of the innovation. Its sole purpose is to present some concepts of the innovation in a simplified form as a prelude to the more detailed description that is presented later.

The innovation disclosed and claimed herein, in one aspect thereof, comprises an apparatus that facilitates removal of contaminants from a fluid sample. One embodiment of such an apparatus can include an intake section capable of sealingly engaging a borehole wall to obtain formation fluid through the wall, and a first flow line in fluid communication with the intake section. At least a portion of the formation fluid obtained by the intake section can be made to pass through the first flow line. Additionally, the apparatus can include a sample chamber with a floating piston. The floating piston can draw at least a first quantity of the portion into the sample chamber from the first flow line, and then the first quantity of the portion can be forced out of the sample chamber. This process can be repeated until sufficient contaminants have been removed, such as those contained in a dead volume between the flow line and the sample chamber. Finally, the floating piston can draw at least a second quantity of the portion into the sample chamber for storage therein as the fluid sample.

In another aspect of the subject innovation, the innovation can comprise a method for obtaining samples with lower levels of contaminants. Such a method can remove contaminants from a fluid sample, and can include the steps of obtaining fluid from a formation and passing a first quantity of the fluid through a sample flow line. A connection between the sample flow line and a sample chamber can be opened, and a first portion of the first quantity of the fluid can be drawn into the sample chamber via a floating piston. The first portion can be forced out of the sample chamber, and this process can be repeated until sufficient contaminants have been removed. Finally, a second portion of the First quantity of the fluid can be drawn into the sample chamber as the fluid sample.

To the accomplishment of the foregoing and related ends certain illustrative aspects of the innovation are described herein in connection with the following description and the annexed drawings. These aspects are indicative, however, of but a few of the various was in which the principles of the innovation can be employed and the subject innovation is intended to include all such aspects and their equivalents. Other advantages and novel features of the innovation will become apparent from the following detailed description of the innovation when considered in conjunction with the drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic view of a subsurface formation penetrated by a wellbore lined with mudcake, depicting the virgin fluid in the subsurface formation.

FIG. 2 is a schematic view of a down hole tool positioned in the wellbore with a probe extending to the formation, depicting the flow of contaminated and virgin fluid into a downhole sampling tool.

FIG. 3 is a schematic view of downhole wireline tool having a fluid sampling device.

FIG. 4 is a schematic view of a downhole drilling tool with an alternate embodiment of the fluid sampling device of FIG. 3.

FIG. 5 is a detailed view of the fluid sampling device of FIG. 3 depicting an intake section and a fluid flow section.

FIG. 6 illustrates a system that can reduce levels of contaminants in a sample chamber in accordance with an embodiment of the subject innovation.

FIG. 7A illustrates an embodiment of another system capable of reducing levels of contaminants obtained in a sample chamber.

FIG. 7B illustrates an embodiment of a further system capable of reducing levels of contaminants obtained in a sample chamber.

FIG. 8 illustrates a method of obtaining a sample of fluid with reduced levels of contaminants.

FIG. 9 is a schematic view of a wellsite having a rig with a downhole tool suspended therefrom and into a subterranean formation.

DETAILED DESCRIPTION

The innovation is now described with reference to the drawings, wherein like reference numerals are used to refer to like elements throughout. In the following description, for purposes of explanation numerous specific details are set forth in order to provide a thorough understanding of the subject innovation. It may he evident, however, that the innovation can be practiced without these specific details. In other instances, well-known structures and devices are shown in block diagram form in order to facilitate describing the innovation.

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. 3, an example environment with which aspects of the present disclosure may be used is shown. In the illustrated example, a downhole tool 302 can be provided, such as a Modular Formation Dynamics Tester (MDT) by Schlumberger Corporation, and further depicted, for example, in U.S. Pat. Nos. 4,936,139 and 4,860,581, the entireties of which are incorporated by reference herein. The downhole tool 302 can be deployable into bore hole 104 and suspended therein with a wire line (e.g., conventional, etc.) 304, or conductor or tubing conventional or coiled tubing, etc.), below a rig 306 as will be appreciated by one of skill in the art. The illustrated tool 302 can be provided with various modules and/or components 308, including but not limited to, a fluid sampling device 310 used to obtain fluid samples from the subsurface formation 102. The fluid sampling device 310 can be provided with a probe 312 extendable through the mudcake 106 and to sidewall 108 of the borehole 104 for collecting samples. The samples can be drawn into the downhole tool 302 through the probe 312.

While FIG. 3 depicts a modular wireline sampling tool that can be used for collecting samples according to one or more aspects of the present innovation, it will be appreciated by one of skill in the art that the subject innovation ma be used in any downhole tool. For example, FIG. 4 shows an alternate downhole tool 402 having a fluid sampling system 404 therein. In this example, the downhole tool 402 can be a drilling tool including a drill string 406 and a drill bit 408. The downhole drilling tool 402 may be of a variety of drilling tools, such as a Measurement-While-Drilling (MWD), Logging-While Drilling (LWD) or other drilling system. The tools 302 and 304 of FIGS. 3 and 4, respectively, may have alternate configurations, such as modular, unitary, wireline, coiled tubing, autonomous, drilling and other variations of downhole tools.

Referring now to FIG, 5, the fluid sampling system 310 of FIG, 3 is shown in greater detail. The sampling system 310 can include an intake section 502 and a flow section 504 capable of selectively drawing fluid into a portion of the downhole tool.

The intake section 502 can include a probe 312 mounted on an extendable base 30 having a seal 508, such as a packer, capable of sealingly engaging the borehole wall 108 around the probe 312. The intake section 502 can be selectively extendable from the downhole tool 302 via extension pistons 510. The probe 312 can be provided with an interior channel 512 and an exterior channel 514 separated by wall 516. In some embodiments, the wall 516 can be concentric with the probe 312. However, the geometry of the probe and the corresponding, wall may be of any geometry. Additionally, one or more walls 516 may be used in various configurations within the probe. Alternatively, an intake section can employ dual packers, as discussed elsewhere herein or in documents incorporated herein by reference.

The flow section 504 includes flow lines 518 and 520 driven by one or more pumps 522. A first flow line 518 is in fluid communication with the interior channel 512, and a second flow line 520 is in fluid communication with the exterior channel 514. The illustrated flow section may include one or more flow control devices, such as the pump 522 and valves 524, 526, 528 and 530 depicted in FIG. 5, capable of selectively drawing fluid into various portions of the flow section 504. Fluid can be drawn from the formation through the interior and exterior channels and into their corresponding flow lines.

In aspects, contaminated fluid may he passed from the formation through exterior channel 514, into lion line 520 amid discharged into the wellbore 104. In the same or other aspects, fluid can pass from the formation into the interior channel 512, through flow line 518 and either diverted into one or more sample chambers 532, or discharged into the wellbore. Once it is determined that the fluid passing into flow line 518 is virgin fluid, a valve 524 and/or 530 may be initiated using known control techniques by manual and/or automatic operation to divert fluid into the sample chamber. In accordance with aspects of the subject innovation, systems and/or methods discussed further herein can be employed to reciprocate the piston in the sample bottle to minimize contaminants obtained in the sample, particularly from fluid volume between a sample flow line and a floating piston in the sample chamber 532 (e.g., contaminants along flow line 518, such as between valve 524 and sample chamber 532, etc.). Upon a determination that contaminants have been sufficiently minimized, a sample of fluid can then be obtained in sample chamber 532 and retained.

The fluid sampling system 310 (or 404, etc.) can also be provided with one or more fluid monitoring systems 534 capable of analyzing the fluid as it enters the probe 312. The fluid monitoring system 534 may be provided with various monitoring devices, such as optical fluid analyzers, as will be discussed more fully herein.

The details of the various arrangements and components of the fluid sampling system 310 (or 404, etc.) described above as well as alternate arrangements and components for the system 310 (or 404, etc.) are apparent to a person of skill in the art in light of the subject disclosure and those of patents and publications incorporated by reference herein. Moreover, the particular arrangement and components of the downhole fluid sampling system 310 (or 404, etc.) may vary depending upon factors in each particular design, use or situation. Thus, neither the system 310 (or 404, etc.) nor the present disclosure are limited to the above described, arrangements and components and may include any suitable components and arrangement. For example, various flow lines, pump placement and valving may be adjusted to provide for as variety of configurations. Similarly, the arrangement and components of the downhole tool 302 may vary depending upon factors in each particular design, or use, situation. The above description of exemplary components and environments of the tool 302 with which the fluid sampling device 310 (or 404, etc.) of the present disclosure may be used is provided as an example only and is not limiting upon the present disclosure.

With continuing reference to FIG. 5, the flow pattern of fluid passing into the downhole tool 302 is illustrated. Initially, as shown in FIG. 1, an invaded zone 110 surrounds the borehole wall 108. Virgin fluid 114 is located in the formation 102 behind the invaded zone 110. At sonic time during the process, as fluid is extracted from the formation 102 into the probe 312, virgin fluid breaks through and enters the probe 312 as shown in FIG. 5. As the fluid flows into the probe, the contaminated fluid 114 in the invaded zone 110 near the interior channel 512 is eventually removed and gives way to the virgin fluid 114. Thus, primarily virgin fluid 114 is drawn into the interior channel 512, while the contaminated fluid 112 flows into the exterior channel 514 of the probe 312. To facilitate such result, fluid can be pumped into and out of the sample chamber one or more times to remove contaminants initially present, or those remaining in the dead volume between the sample flow line 518 and the sample chamber 532. Additionally, it is to be understood that while FIG. 5 illustrates a single sample chamber 532, substantially any number of sample chambers can be used in various embodiments. Moreover, in various embodiments, systems and methods of the subject innovation can be used in connection with other fluid sampling systems, such as those described in U.S. Pat. No. 8,210,260, the entirety of which is incorporated herein by reference.

Turning now to FIG. 6, illustrated is a fluid sampling system 600 with multiple sample chambers that can be used with systems and methods of the subject innovation. Although two sets of three sample chambers 532 are illustrated in system 600, it is to be appreciated that substantially any number of sample chambers 532 can be used in connection with the subject innovation. Each sample chamber can be associated with a normally closed valve 602 and a normally open valve 604, and throttle/seal valves 606 can be associated with the flowline from the probe/packer inlet at 608 to the wellbore outlet at 610. These valves 602, 604, and 606 can be controlled by electronics for computer, etc.) 612. A relief valve 614 can be included to control or limit the pressure in system 600.

In operation, valves 602, 604, and 606 can be controlled to direct fluid into sample chambers 532. As explained herein, fluid directed into sample chambers can contain contaminants, such as from the dead volume between a sample flow line and the floating piston of the sample chamber(s) 532. The volume of fluid in one or more of the sample chambers 532 (e.g., each sample chamber 532) can then be pumped out of the back side of the sample chamber by using the floating piston 616 in a manner similar to a displacement unit. This action of the floating piston 616 can be controlled automatically or manually (e.g., by a user at the surface, a remote location, etc.). This fluid can be discharged into the wellbore 104, e.g., via an optional relief valve 614 or otherwise. In some situations, this process may need to be repeated more than once in order to obtain a sample of virgin fluid. Drawing fluid into the sample chamber(s) 532 and back out via reciprocation of floating piston(s) 616 can be repeated until a sufficient level of confidence is gained that the contaminated fluid (e.g., of the dead volume in the flow line 518, etc.) has been removed. This confidence can be gained based at least in part on any of a number of factors, which can include the relative volume of potentially contaminated fluid to that of the sample chamber (e.g., determining a number of iterations based on the ratio of the volumes, so as to ensure virgin fluid will ultimately be drawn into the sample chamber, etc.), based on a measured level of contamination of the fluid prior to entering the sample chamber 532 as determined using techniques known in the art Or discussed herein (e.g., via an optical fluid analyzer (OFA), etc.), based on a measured level of contamination of fluid pumped out of the sample chamber 532, etc. After the fluid is sufficiently free from contaminants, virgin fluid can be drawn into the sample chamber 532 for storage therein.

Turning to FIGS. 7A and 7B, illustrated are two alternate embodiments of a system according to the subject innovation. In FIG. 7A, as illustrated, sample chamber 532 can employ a mechanical device 702 (e.g., a spring, etc.) to force fluid back into a flow line (e.g., flow line 518) to remove potential contaminants and ensure virgin fluid is obtained in sample chamber 532. Similarly, in FIG. 7B, a pressure-based, pneumatic or similar device 704 (e.g., a closed nitrogen charge, etc.) can be similarly used to push fluid back into a flow line. As illustrated, a system such as in FIG. 7B can include manual valves 706. Embodiments similar to those of FIGS. 7A and 7B, that can employ a device to force fluid back into the flow line, can be used in systems where it is not possible to push fluid out the back side of a sample chamber 532. The actions of mechanical and/or pressure-based devices discussed in connection with FIGS. 7A and 7B can be controlled automatically or manually (e.g., by a user at the surface, a remote location, etc.).

FIG. 8 illustrates a methodology 800 of improving the quality of fluid obtained in a sample chamber in accordance with aspects of the subject innovation. While for purposes of simplicity of explanation, the one or more methodologies shown herein, e.g., in the form of a flow chart, are shown and described as a series of acts, it is to be understood and appreciated that the subject innovation is not limited by the order of acts, as some acts may, in accordance with the innovation, occur in a different order and/or concurrently with other acts from that shown and described herein. For example, those skilled in the art will understand and appreciate that a methodology could alternatively be represented as a series of interrelated states or events, such as in a state diagram. Moreover, not all illustrated acts may be required to implement a methodology in accordance with the innovation.

Method 800 can begin at step 802, wherein fluid can be allowed to pass through a sample flow line, such as flow line 518. Next, at 804, as determination can be made that the fluid passing through the sample flow line is virgin fluid, i.e., that it is sufficiently free of contaminants. This determination can be made based on analysis such as discussed herein (e.g., via an OFA, etc.). If necessary, such as if the fluid is determined to have unacceptably high levels of contaminants, steps 802 and. 804 can be repeated with further monitoring of the fluid until the fluid is determined to be virgin fluid. Next, at 806, a connection between the sample flow line and a sample chamber can be opened. At 808, fluid can be drawn into the sample chamber. However, this fluid may have unacceptable levels of contaminants, for example, due to the dead volume of fluid between the flow line and the sample chamber. Because of this, at 810, the fluid can be forced out of the sample chamber to “flush” the sample chamber and remove contaminants that may be contained in it. The fluid can be forced out of the sample chamber by pushing out of the back of the sample chamber by using the floating piston, by using a mechanical device (such as a spring, etc.) to force it out of the sample chamber, by using pressure (e.g., a pneumatic device such as a closed nitrogen charge, etc.) to force the fluid out of the sample chamber, etc.

Next, at 812, a determination can be made whether to re-“flush” the sample chamber by repeating steps 808 and 810, by determining whether sufficient contaminants have been removed, i.e., whether the fluid that will next enter the sample chamber is virgin fluid. This determination can he based on measurements of fluid before or after being drawing into and forced out of the sample chamber, based on system parameters (e.g., one or more relevant volumes, etc.), other factors, or a combination of factors. If it is determined that it is necessary to re-“flush” the sample chamber, method 800 can return to step 808, and can repeat steps 808, 810, and 812 until it is determined that sufficient contaminants have been removed. If not, the method can finish at step 814, by drawing fluid into the sample chamber to be retained therein as a representative sample of the formation (e.g., for testing, etc.).

FIG. 9 illustrates a wellsite system 900 that the subject innovation can be used in connection with. The wellsite system includes a surface system 902, a downhole system 904 and a surface control unit 906. In the illustrated embodiment, a borehole 908 can be formed by rotary drilling in a conventional manner. In light of the teachings herein, those of ordinary skill in the art will appreciate, however, that the subject innovation can be applied in downhole applications other than conventional rotary drilling, and is not limited to land-based rigs. Examples of other downhole application may involve the use of wireline tools (see, e.g., FIG. 2 or 3), casing drilling, coiled tubing, and other downhole tools.

The downhole system 904 includes a drill string 910 suspended within the borehole 908 with a drill bit 912 at its lower end. The surface system 902 includes the land-based platform and derrick assembly 914 positioned over the borehole 908 penetrating a subsurface formation 102. The assembly 914 includes a rotary table 916, kelly 918, hook 920 and rotary swivel 922. The drill string 910 is rotated by the rotary table 916, energized by apparatus not shown, which engages the kelly 918 at the upper end of the drill string. The drill string 910 is suspended from a hook 920, attached to a traveling, block (also not shown), through the kelly 918 and the rotary swivel 922, which permits rotation of the drill string relative to the hook.

The surface system further includes drilling fluid or mud 926 stored in a pit 928 formed at the well site. A pump 930 delivers the drilling fluid 926 to the interior of the drill string 910 via a port in the swivel 922, inducing the drilling fluid to now downwardly through the drill string 910 as indicated by the directional arrow 932. The drilling fluid exits the drill string 910 via ports in the drill bit 912, and then circulates upwardly through the region between the outside of the drill string and the wall of the borehole, called the annulus, as indicated by the directional arrows 934. In this manner, the drilling fluid lubricates the drill bit 912 and carries formation cuttings up to the surface as it is returned to the pit 928 for recirculation.

The drill string 910 further includes a bottom hole assembly (BHA), generally referred to as BHA 936, near the drill bit 912 (in other words, within several drill collar lengths from the drill bit). The bottom hole assembly includes capabilities for measuring, processing, and storing information, as well as communicating with the surface. The BHA 936 can include one or more of drill collars 938, 940, or 942 for performing various other measurement functions.

The BHA 936 includes the formation evaluation assembly 944 for determining and communicating one or more properties of the formation 102 surrounding borehole 908, such as formation resistivity (or conductivity), natural radiation, density (gamma ray or neutron), and pore pressure. The BHA also includes a telemetry assembly 946 for communicating with the surface unit 906. The telemetry assembly 946 includes drill collar 942 that houses a measurement-while-drilling (MWD) tool. The telemetry assembly further includes an apparatus 948 for generating electrical power to the downhole system. While a mud pulse system is depicted with a generator powered by the flow of the drilling fluid 924 that flows through the drill string 910 and the MWD drill collar 942, other telemetry, power and/or batter systems may be employed.

Formation evaluation assembly 944 includes drill collar 940 with stabilizers or ribs 950 and a probe 952 positioned in the stabilizer. The formation evaluation assembly is used to draw fluid into the tool for testing. The probe 952 may be similar to the probe as described elsewhere herein or in documents incorporated by reference. Flow circuitry and other features may also be provided in the formation evaluation assembly 944. The probe may be positioned in a stabilizer blade as described, for example, in U.S. Patent Application Publication No. 2005/0109538, the entirety of which is incorporated by reference herein.

Sensors are located about the wellsite to collect data, for example in real time, concerning the operation of the wellsite, as well as conditions at the wellsite. For example, monitors, such as cameras 954, may be provided to provide pictures of the operation. Surface sensors or gauges 956 are disposed about the surface systems to provide information about the surface unit, such as standpipe pressure, hook load, depth, surface torque, rotary rpm, among others. Downhole sensors or gauges 958 may be disposed about the drilling tool and/or wellbore to provide information about downhole conditions, such as wellbore pressure, weight, on bit, torque on bit, direction, inclination, collar rpm, tool temperature, annular temperature and toolface, among others. Additional formation evaluation sensors 960 may be positioned in the formation evaluation sensors to measure downhole properties. Examples of such sensors are described elsewhere herein or in documents incorporated by reference. The information collected by the sensors and/or cameras is conveyed to the surface system, the downhole system and/or the surface control unit

The telemetry assembly 946 uses mud pulse telemetry to communicate with the surface system. The MWD tool 942 of the telemetry assembly 946 may include, for example, a transmitter that generates a signal, such as an acoustic or electromagnetic, signal, which is representative of the measured drilling parameters. The generated signal is received at the surface by transducers (not shown), that convert the received acoustical signals to electronic signals for further processing, storage, encryption and use according to conventional methods and systems. Communication between the downhole and surface systems is depicted as being mud pulse telemetry, such as the one described in U.S. Pat. No. 5,517,464, the entirety of which is incorporated herein by reference. It will be appreciated by one of skill in the art that a variety of telemetry systems may be employed, such as wired drill pipe, electromagnetic or other known telemetry systems. It will be appreciated that when using other downhole tools, such as wireline took, other telemetry systems, such as the wireline cable or electromagnetic telemetry, may be used.

The telemetry system provides a communication link 962 between the downhole system 904 and the surface control unit 906. An additional communication link 964 may be provided between the surface system 902 and the surface control unit 906. The downhole system 904 may also communicate with the surface system 902. The surface unit may communicate with the downhole system directly, or via the surface unit. The downhole system may also communicate with the surface unit directly, or via the surface system. Communications may also pass from the surface system to a remote location 964.

One or more surface, remote or wellsite systems may be present. Communications may be manipulated through each of these locations as necessary. The surface system may be located at or near a wellsite to provide an operator with information about wellsite conditions. The operator may be provided with a monitor that provides information concerning the wellsite operations. For example, the monitor may display graphical images or other data concerning wellbore output.

The operator may be provided with a surface control system 966. The surface control system includes surface processor 968 to process the data, and a surface memory 970 to store the data. The operator may also be provided with as surface controller 972 to make changes to a wellsite setup to alter the wellsite operations. Based on the data received and/or an analysis of the data, the operator may manually make such adjustments. These adjustments may also be made at a remote location. In some cases, the adjustments may be made automatically.

Drill collar 938 may be provided with a downhole control assembly 974. The downhole control assembly includes a downhole processor for processing downhole data, and a downhole memory for storing the data. A downhole controller may also be provided to selectively activate various downhole tools. The downhole control assembly may be used to collect, store and analyze data received from various wellsite sensors. The downhole processor may send messages to the downhole controller to activate tools in response to data received. In this manner, the downhole operations may be automated to make adjustments in response to downhole data analysis. Such downhole controllers may also permit input and/or manual control of such adjustments by the surface and/or remote control unit. The downhole control system may work with or separate from one or more of the other control systems.

The wellsite setup includes tool configurations and operational settings. The tool configurations may include for example, the size of the tool housing, the type of hit, the size of the probe, the type of telemetry assembly, etc. Adjustments to the tool configurations may be made by replacing tool components, or adjusting the assembly of the tool.

For example, it may be possible to select tool configurations, such as a specific probe with a predefined diameter to meet the testing requirements. However, it may be necessary to replace the probe with a different diameter probe to perform as desired. If the probe is provided with adjustable features, it may be possible to adjust the diameter without replacing the probe.

Operational settings may also be adjusted to meet the needs of the wellsite operations. Operational settings may include tool settings, such as flow rates, rotational speeds, pressure settings, etc. Adjustments to the operational settings may typically be made by adjusting tool controls. For example, flow rates into the probe may be adjusted by altering the flow rate settings on pumps that drive flow through sampling and contamination flowlines. Additionally, it may be possible to manipulate flow through the flowlines by selectively activating certain valves and/or diverters (e,g., those illustrated in FIGS. 5, 6, 7A, and 7B).

What has been described above includes examples of the innovation. It is, of course, not possible to describe every conceivable combination of components or methodologies for purposes of describing the subject innovation, but one of ordinary skill in the art may recognize that many further combinations and permutations of the innovation are possible. Accordingly, the innovation is intended to embrace all such alterations, modifications and variations that fall within the spirit and scope of the appended churns. Furthermore, to the extent that the term “includes” is used in either the detailed description or the claims, such term is intended to be inclusive in a manner similar to the term “comprising” as “comprising” is interpreted when employed as a transitional word in a claim.

Claims

1. An apparatus that facilitates removal of contaminants from a fluid sample, comprising:

an intake section configured to sealingly engage a borehole wail to obtain formation fluid, through the borehole wall;

a first flow line in fluid communication with the intake section, wherein at least a portion of the formation fluid obtained by the intake section passes through the first flow line; and

a sample chamber comprising a floating piston, wherein the floating piston is configured to draw at least a first quantity of the portion into the sample chamber from the first flow line, wherein the first quantity of the portion is forced out of the sample chamber, and wherein the floating piston is configured to draw at least a second quantity of the portion into the sample chamber for storage therein as the fluid sample.

2. The apparatus of claim 1, wherein the floating piston is configured to draw the first quantity into the sample chamber through a front end of the sample chamber, and the floating piston is configured to force the first quantity out through a back end of the sample chamber.

3. The apparatus of claim 1, further comprising a mechanical device configured to force out the first quantity from the sample chamber.

4. The apparatus of claim 3, wherein the mechanical device comprises a spring.

5. The apparatus of claim 1, further comprising:

a pressure-based device configured to force the first quantity out of the sample chamber.

6. The apparatus of claim 5, wherein the pressure-based device comprises a closed nitrogen charge.

7. The apparatus of claim 1, wherein the floating piston is configured to draw at least a third quantity of the portion into the sample chamber from the first flow line before the floating piston draws at least the second quantity of the portion, wherein the third quantity of the portion is forced out of the sample chamber.

8. The apparatus of claim 7, wherein the second quantity is drawn into the sample chamber based at least in part on a determination that insufficient contaminants have been removed.

9. The apparatus of claim 1, further comprising:

a second flow line in fluid communication with the intake section, wherein at least a second portion of the formation fluid obtained by the intake section passes through the second flow line, and wherein the second portion comprises more contaminants than the first quantity.

10. The apparatus of claim 1, wherein the floating piston is automatically controlled.

11. The apparatus of claim 1, wherein the intake section comprises a probe.

12. The apparatus of claim 1, wherein the intake section comprises dual packers.

13. A method of removing contaminants from a fluid sample, comprising:

obtaining fluid from a formation;

passing a first quantity of the fluid through a sample flow line;

opening a connection between the sample flow line and a sample chamber:

drawing, a first portion of the first, quantity of the fluid into the sample chamber via a floating piston;

forcing the first portion out of the sample chamber; and

drawing a second portion of the first quantity of the fluid into the sample chamber as the fluid sample.

14. The method of claim 13, wherein the drawing the first portion into the sample chamber comprises drawing the first portion in through a front end of the sample chamber, and wherein the forcing the first portion out of the sample chamber comprises employing the floating piston to force the first portion out of the back of the sample chamber.

15. The method of claim 13, wherein the forcing the first portion out of the sample chamber comprises using a mechanical device to force the first portion out of the sample chamber.

16. The method of claim 15, wherein the mechanical device comprises a spring.

17. The method of claim 13, wherein the forcing the first portion out of the sample chamber comprises employing a pressure-based device to force the first portion out of the sample chamber.

18. The method of claim 17, wherein the pressure-based device comprises a closed nitrogen charge.

19. The method of claim 13, further comprising:

determining whether sufficient contaminants have been removed from the first quantity.

20. The method of claim 19, further comprising:

drawing at least one additional portion of the first quantity of the fluid into the sample chamber via the floating piston prior to drawing the second portion; and

forcing the at least one additional portion out of the sample chamber.

21. The method of claim 20, further comprising:

selecting the number of additional portions drawn, wherein the number of additional portions is selected to remove sufficient contaminants from the first quantity.