U.S. patent application number 13/609903 was filed with the patent office on 2014-03-13 for minimization of contaminants in a sample chamber.
The applicant listed for this patent is Pierre Campanac, Nathan Landsiedel, Yoshitake Yajima. Invention is credited to Pierre Campanac, Nathan Landsiedel, Yoshitake Yajima.
Application Number | 20140069640 13/609903 |
Document ID | / |
Family ID | 49170562 |
Filed Date | 2014-03-13 |
United States Patent
Application |
20140069640 |
Kind Code |
A1 |
Yajima; Yoshitake ; et
al. |
March 13, 2014 |
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.
Inventors: |
Yajima; Yoshitake; (Sugar
Land, TX) ; Landsiedel; Nathan; (Fresno, TX) ;
Campanac; Pierre; (Sugar Land, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Yajima; Yoshitake
Landsiedel; Nathan
Campanac; Pierre |
Sugar Land
Fresno
Sugar Land |
TX
TX
TX |
US
US
US |
|
|
Family ID: |
49170562 |
Appl. No.: |
13/609903 |
Filed: |
September 11, 2012 |
Current U.S.
Class: |
166/264 ;
166/162 |
Current CPC
Class: |
E21B 49/10 20130101 |
Class at
Publication: |
166/264 ;
166/162 |
International
Class: |
E21B 49/08 20060101
E21B049/08 |
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.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] None.
FIELD OF THE INVENTION
[0002] Aspects relate to downhole drilling. More specifically,
aspects relate to minimization of contaminants in sample chambers
in downhole tools.
BACKGROUND INFORMATION
[0003] 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.
[0004] 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.
[0005] 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.
[0006] 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.
[0007] 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.
[0008] 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.
[0009] 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.
[0010] 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.
[0011] 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.
[0012] 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,
[0013] 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.
[0014] 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.
[0015] Despite the existence of techniques for performing formation
evaluation, conventional systems fail to adequately mitigate the
problem of contamination.
SUMMARY
[0016] 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.
[0017] 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.
[0018] 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.
[0019] 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
[0020] 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.
[0021] 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.
[0022] FIG. 3 is a schematic view of downhole wireline tool having
a fluid sampling device.
[0023] FIG. 4 is a schematic view of a downhole drilling tool with
an alternate embodiment of the fluid sampling device of FIG. 3.
[0024] FIG. 5 is a detailed view of the fluid sampling device of
FIG. 3 depicting an intake section and a fluid flow section.
[0025] FIG. 6 illustrates a system that can reduce levels of
contaminants in a sample chamber in accordance with an embodiment
of the subject innovation.
[0026] FIG. 7A illustrates an embodiment of another system capable
of reducing levels of contaminants obtained in a sample
chamber.
[0027] FIG. 7B illustrates an embodiment of a further system
capable of reducing levels of contaminants obtained in a sample
chamber.
[0028] FIG. 8 illustrates a method of obtaining a sample of fluid
with reduced levels of contaminants.
[0029] 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
[0030] 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.
[0031] 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.
[0032] 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.
[0033] 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.
[0034] 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.
[0035] 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.
[0036] 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.
[0037] 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.
[0038] 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.
[0039] 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.
[0040] 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.
[0041] 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.
[0042] 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.
[0043] 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.).
[0044] 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.
[0045] 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.
[0046] 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.).
[0047] 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.
[0048] 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.
[0049] 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.
[0050] 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.
[0051] 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.
[0052] 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.
[0053] 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
[0054] 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.
[0055] 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.
[0056] 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.
[0057] 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.
[0058] 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.
[0059] 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.
[0060] 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.
[0061] 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).
[0062] 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.
* * * * *