U.S. patent application number 17/719097 was filed with the patent office on 2022-07-28 for downhole hydrogen sulfide capture and measurement.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Julia Golovko, Christopher Michael Jones, James M. Price, Anthony Herman VanZuilekom.
Application Number | 20220235657 17/719097 |
Document ID | / |
Family ID | |
Filed Date | 2022-07-28 |
United States Patent
Application |
20220235657 |
Kind Code |
A1 |
Golovko; Julia ; et
al. |
July 28, 2022 |
Downhole Hydrogen Sulfide Capture and Measurement
Abstract
Disclosed herein are methods and systems for capture and
measurement of a target component. A fluid sampling tool for
sampling fluid from a subterranean formation may include a sample
chamber having a fluid inlet, wherein the sample chamber is lined
with a coating of a material that can reversibly hold a target
component.
Inventors: |
Golovko; Julia; (Houston,
TX) ; Price; James M.; (Cypress, TX) ; Jones;
Christopher Michael; (Katy, TX) ; VanZuilekom;
Anthony Herman; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Appl. No.: |
17/719097 |
Filed: |
April 12, 2022 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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16442626 |
Jun 17, 2019 |
11352884 |
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17719097 |
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International
Class: |
E21B 49/10 20060101
E21B049/10; E21B 49/08 20060101 E21B049/08; G01N 1/22 20060101
G01N001/22; G01N 33/00 20060101 G01N033/00 |
Claims
1. A system comprising: a chamber housing comprising a chamber
receptacle for receiving a sample chamber; a pump in fluid
communication with the chamber housing for creating a pressure to
drive a target component from the sample chamber to an analytical
technique; and a processor operable to receive inputs from the
analytical technique to determine a concentration of the target
component.
2. The system of claim 1, wherein the analytical technique is a
fluid analyzer.
3. The system of claim 2, wherein the fluid analyzer is selected
from a mass spectrometer, a gas chromatograph, an optical sensor,
and combinations thereof.
4. The system of claim 1, wherein the analytical technique measures
a desorbed component.
5. The system of claim 1, wherein the analytical technique is a gas
chromatography, a mass spectrometry, or an optical sensor.
6. The system of claim 1, further comprising a heating element
disposed in the chamber housing arranged to heat the sample
chamber.
7. The system of claim 6, wherein the heating element provides heat
electrically or chemically.
8. The system of claim 1, wherein the pump is a vacuum pump or a
low volume pump.
9. The system of claim 1, wherein the sample chamber holds
micro-samples.
10. The system of claim 1, wherein the target component is desorbed
in the sample chamber.
11. A method comprising: inserting a target component into a sample
chamber; driving the target component from the sample chamber to an
analytical technique using a pump; and identifying a concentration
of the target component using a processor; and extrapolating a
quantity of the target component to a reservoir concentration.
12. The method of claim 11, further comprising desorbing the target
component in the samples chamber.
13. The method of claim 11, wherein the analytical technique is a
fluid analyzer.
14. The method of claim 13, wherein the fluid analyzer is selected
from a mass spectrometer, a gas chromatograph, an optical sensor,
and combinations thereof.
15. The method of claim 11, wherein the analytical technique
measures a desorbed component.
16. The method of claim 11, wherein the analytical technique is a
gas chromatography, a mass spectrometry, or an optical sensor.
17. The method of claim 11, further comprising a heating element to
heat the sample chamber.
18. The method of claim 17, wherein the heating element provides
heat electrically or chemically.
19. The method of claim 11, wherein the pump is a vacuum pump or a
low volume pump.
20. The method of claim 11, wherein the sample chamber holds
micro-samples.
Description
BACKGROUND
[0001] Wells may be drilled at various depths to access and produce
oil, gas, minerals, and other naturally-occurring deposits from
subterranean geological formations. The drilling of a well is
typically accomplished with a drill bit that is rotated within the
well to advance the well by removing topsoil, sand, clay,
limestone, calcites, dolomites, or other materials. The drill bit
is typically attached to a drill string that may be rotated to
drive the drill bit and within which drilling fluid, referred to as
"drilling mud" or "mud", may be delivered downhole. The drilling
mud is used to cool and lubricate the drill bit and downhole
equipment and is also used to transport any rock fragments or other
cuttings to the surface of the well.
[0002] It is often desired to collect a representative sample of
formation or reservoir fluids (e.g., hydrocarbons) to further
evaluate drilling operations and production potential, or to detect
the presence of certain gases or other materials in the formation
that may affect well performance. For example, hydrogen sulfide
(H2S), a poisonous, corrosive, and flammable gas can occur in
formation fluids, and its presence in the wellbore in significant
concentrations may result in damage to wellbore components or
dangerous conditions for well operators at the surface. However,
H2S concentration in formation fluids is often underestimated with
current measurement techniques, for example, due to losses via
absorption/adsorption on tool surfaces and/or during sample
transfers.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] The features and advantages of certain embodiments will be
more readily appreciated when considered in conjunction with the
accompanying figures. The figures are not to be construed as
limiting any of the preferred embodiments.
[0004] FIG. 1A illustrates a schematic view of a well in which an
example embodiment of a fluid sample system is deployed.
[0005] FIG. 1B illustrates a schematic view of another well in
which an example embodiment of a fluid sample system is
deployed.
[0006] FIG. 2 illustrates a schematic view of an example embodiment
of a fluid sampling tool.
[0007] FIG. 3 illustrates an enlarged schematic view of an example
embodiment the fluid sampling tool of FIG. 2
[0008] FIG. 4 illustrates a cross-sectional view an example
embodiment of a sample chamber coated with a material that is
reversibly sorbent.
[0009] FIG. 5A illustrates an enlarged cross-sectional view of a
sample chamber showing an example embodiment of a porous
coating.
[0010] FIG. 5B illustrates an enlarged cross-sectional view of a
sample chamber showing an example embodiment of a structured
coating,
[0011] FIG. 6 illustrates an example diagram of an example test
system for target component measurement.
DETAILED DESCRIPTION
[0012] The present disclosure relates to subterranean operations
and, more particularly, embodiments disclosed herein provide
methods and systems for capture and measurement of a target
component.
[0013] Embodiments may include sampling of formation fluids from a
wellbore to determine a concentration of a target component in the
formation fluid. Target component may include any of a variety of
gases, vapors, or liquids, where quantification in formations
fluids may be desired, including, but not limited to, H2S, mercury,
and carbon dioxide, among others. By way of example, H2S is a
volatile chemical that oxidizes easily, is corrosive to downhole
tools, and is poisonous and explosive. The presence of H2S in a
formation may increase the cost of extracting and processing
formation fluids from a well and also present a safety hazard to
well operators, Accurate measurement of H2S (or other target
components) in the formation fluids can better enable well
operators to make decisions about completing a well so that
formation fluids can be economically extracted while maintaining
safe conditions for well operators. In addition, it may desirable
to know concentration of mercury and carbon dioxide as well, as
these components can also be corrosive.
[0014] The fluid sampling tools described herein may vary in
design, but embodiments of the fluid sampling tools typically may
include an inlet, an outlet, and a sampling chamber. Embodiments
may further include two or more sampling chambers. The inlet and
outlet may be fluidly connected to the fluid within the wellbore
that is being extracted from a subterranean formation. In
operation, a fluid sample may be gathered into the sampling chamber
from the wellbore for analysis. Embodiments may include coating
inner surfaces of the sampling chamber with a material that can
reversibly sorb the target component. In this manner, the target
component in the fluid sample should be sorbed by the coating,
instead of being lost via sorbtion on tool surfaces. At a desired
time, for example, after recovery of the sample tool to the well
surface, the target component can be desorbed and measured. Given a
known volume of formation fluid sampled and amount of target
component, the concentration of the target component in the sample
can be determined. Multiple component measurements from multiple
sample chambers (e.g., two or more) may be obtained, for example,
to extrapolate to reservoir conditions. The component measurements
may be obtained at different times in the wellbore.
[0015] The fluid sampling tools, systems and methods described
herein may be used with any of the various techniques employed for
evaluating a well, including without limitation wireline formation
testing (WFT), measurement while drilling (MWD), and logging while
drilling (LWD). The various tools and sampling units described
herein may be delivered downhole as part of a wireline-delivered
downhole assembly or as a part of a drill string. It should, also
be apparent that given the benefit of this disclosure, the
apparatuses and methods described herein have applications in
downhole operations other than drilling, and may also be used after
a well is completed.
[0016] FIG. 1A illustrates a fluid sampling and analysis system 100
according to an illustrative embodiment used in a well 102 having a
wellbore 104 that extends from a surface 108 of the well 102 to or
through a subterranean formation 112. While the wellbore 104 is
shown extending generally vertically into the subterranean
formation 112, the principles described herein are also applicable
to wellbores that extend at an angle through the subterranean
formations 112, such as horizontal and slanted wellbores. For
example, although FIG. 1A shows wellbore 104 that is vertical or
low inclination, high inclination angle or horizontal placement of
the wellbore 104 and equipment is also possible. In addition, it
should be noted that while FIG. 1A generally depicts a land-based
operation, those skilled in the art should readily recognize that
the principles described herein are equally applicable to subsea
operations that employ floating or sea-based platforms and rigs,
without departing from the scope of the disclosure.
[0017] The well 102 is illustrated with the fluid sampling and
analysis system 100 being deployed in a drilling assembly 114. In
the embodiment illustrated in FIG. 1A, the well 102 is formed by a
drilling process in which a drill bit 116 is turned by a drill
string 120 that extends from the drill bit 116 to the surface 108
of the well 102. The drill string 120 may be made up of one or more
connected tubes or pipes, of varying or similar cross-section. The
drill string 120 may refer to the collection of pipes or tubes as a
single component, or alternatively to the individual pipes or tubes
that include the string. The term "drill string" is not meant to be
limiting in nature and may refer to any component or components
that are capable of transferring rotational energy from the surface
of the well to the drill bit. In several embodiments, the drill
string 120 may include a central passage disposed longitudinally in
the drill string 120 and capable of allowing fluid communication
between the surface 108 of the well 102 and downhole locations.
[0018] At or near the surface 108 of the well 102, the drill string
120 may include or be coupled to a kelly 128. The kelly 128 may
have a square, hexagonal, octagonal, or other suitable
cross-section. The kelly 128 may be connected at one end to the
remainder of the drill string 120 and at an opposite end to a
rotary swivel 132. As illustrated, the kelly 120 may pass through a
rotary table 136 that is capable of rotating the kelly 128 and thus
the remainder of the drill string 120 and drill bit 116. The rotary
swivel 132 should allow the kelly 128 to rotate without rotational
motion being imparted to the rotary swivel 132. A hook 138, cable
142, traveling block (not shown), and hoist (not shown) may be
provided to lift or lower the drill bit 116, drill string 120,
kelly 128 and rotary swivel 132. The kelly 128 and swivel 132 may
be raised or lowered as needed to add additional sections of tubing
to the drill string 120 as the drill bit 116 advances, or to remove
sections of tubing from the drill string 120 if removal of the
drill string 120 and drill bit 116 from the well 102 is
desired.
[0019] A reservoir 144 may be positioned at the surface 108 and
holds drilling fluid 148 for delivery to the well 102 during
drilling operations. A supply line 152 may fluidly couple the
reservoir 144 and the inner passage of the drill string 120. A pump
156 may drive the drilling fluid 148 through the supply line 152
and downhole to lubricate the drill bit 116 during drilling and to
carry cuttings from the drilling process back to the surface 108.
After traveling downhole, the drilling fluid 148 returns to the
surface 108 by way of an annulus 160 formed between the drill
string 120 and the wellbore 104. At the surface 108, the drilling
mud 148 may returned to the reservoir 144 through a return line
164. The drilling mud 148 may be filtered or otherwise processed
prior to recirculation through the well 102.
[0020] FIB. 1B illustrates a schematic view of another embodiment
of well 102 in which an example embodiment of fluid analysis system
100 may be deployed. As illustrated, fluid analysis system 100 may
be deployed as part of a wireline assembly 115, either onshore of
offshore. As illustrated, the wireline assembly 115 may include a
winch 117, for example, to raise and lower a downhole portion of
the wireline assembly 115 into the well 102, As illustrated, fluid
analysis system 100 may include fluid sampling tool 170 attached to
the winch 117. In examples, it should be noted that fluid sampling
tool 170 may not be attached to a winch unit 104. Fluid sampling
tool 170 may be supported by rig 172 at surface 108.
[0021] Fluid sampling tool 170 may be tethered to the winch 117
through wireline 174. While FIG. 1B illustrates wireline 174, it
should be understood that other suitable conveyances may also be
used for providing mechanical conveyance to fluid sampling tool in
the well 102, including, but not limited to, slickline, coiled
tubing, pipe, drill pipe, drill string, downhole tractor, or the
like. In some examples, the conveyance may provide mechanical
suspension, as well as electrical connectivity, for fluid sampling
tool 170. Wireline 174 may include, in some instances, a plurality
of electrical conductors extending from winch 117. By way of
example, wireline 174 may include an inner core of seven electrical
conductors (not shown) covered by an insulating wrap. An inner and
outer steel armor sheath may be wrapped in a helix in opposite
directions around the conductors. The electrical conductors may be
used for communicating power and telemetry downhole to fluid
sampling tool 170.
[0022] With reference to both FIGS. 1A and 1B, operation of fluid
sampling tool 170 for sample collection will now be described in
accordance with example embodiments. Fluid sampling tool 170 may be
raised and lowered into well 102 on drill string 120 (FIG. 1A) and
wireline 174. (FIG. 1B). Fluid sampling tool 170 may be positioned
downhole to obtain fluid samples from the subterranean formation
112 for analysis. The formation fluid and, thus the fluid sample
may be contaminated with, or otherwise contain, the target
component. In some embodiments, the target component may be
contained in the fluid sample in small quantities, for example,
less than 500 parts per million ("ppm"). For example, the target
component mar be present in the fluid sample in an amount from
about 1 ppm to about 500 ppm, about 100 ppm to about 200 ppm, about
1 ppm to about 100 ppm, or about 5 to about 10 ppm. The fluid
sampling tool 170 may be operable to measure, process, and
communicate data regarding the subterranean formation 112, fluid
from the subterranean formation 112, or other operations occurring
downhole. After recovery, the fluid sample may be analyzed, for
example, to quantify the concentration of the target component.
This information, including information gathered from analysis of
the fluid sample, allows well operators to determine, among other
things, the concentration the target component within the fluid
being extracted from the subterranean formation 112 to make
intelligent decisions about ongoing operation of the well 102. In
some embodiments, the data measured and collected by the fluid
sampling tool 170 may include, without limitation, pressure,
temperature, flow, acceleration (seismic and acoustic), and strain
data. As described in more detail below, the fluid sampling tool
170 may include a communications subsystem, including a transceiver
for communicating using mud pulse telemetry or another suitable
method of wired or wireless communication with a surface controller
184. The transceiver may transmit data gathered by the fluid
sampling tool 170 or receive instructions from a well operator via
the surface controller 184 to operate the fluid sampling tool
170.
[0023] Referring now to FIG. 2, an example embodiment of a fluid
sampling tool 170 is illustrated as a tool for gathering fluid
samples from a formation for subsequent analysis and testing. It
should be understood that the fluid sampling tool. 170 shown on
FIG. 2 is merely illustrative and the example embodiments disclosed
herein may be used with other tool configurations. In an
embodiment, the fluid sampling tool 170 includes a transceiver 202
through which the fluid sampling tool 170 may communicate with
other actuators and sensors in a conveyance drill string 120 on
FIG. 1A or wireline 174 on FIG. TB), the conveyance's
communications system, and with a surface controller (surface
controller 184 on FIG. 1A). In an embodiment, the transceiver 202
is also the port through which various actuators (e.g. valves) and
sensors (e.g., temperature and pressure sensors) in the fluid
sampling tool 170 are controlled and monitored by, for example, a
computer in another part of the conveyance or by the surface
controller 184. In an embodiment; the transceiver 202 includes a
computer that exercises the control and monitoring function.
[0024] The fluid sampling tool 170 may include a dual probe section
204, which extracts fluid from the formation (e.g., formation 112
on FIGS. 1A and 1B), as described in more detail below, and
delivers it to a channel 206 that extends from one end of the fluid
sampling tool 170 to the other. The channel 206 can be connected to
other tools or portions of the fluid sampling tool 170 arranged in
series. The fluid sampling tool 170 may also include a gauge
section 208, which includes sensors to allow measurement of
properties, such as temperature and pressure, of the fluid in the
channel 206. The fluid sampling tool 170 may also include a
flow-control pump-out section 210, which includes a pump 212 for
pumping fluid through the channel 206. The fluid sampling tool 170
also includes one or more chambers, such as multi-chamber sections
214, which are described in more detail below.
[0025] In some embodiments, the dual probe section 204 includes two
probes 218, 220 which extend from the fluid sampling tool 170 and
press against the borehole wall to receive fluid for sampling.
Probe channels 222, 224 connect the probes 218, 220 to the channel
206. The pump 212 can be used to pump fluids from the reservoir,
through the probe channels 222, 224 and to the channel 206.
Alternatively, a low volume pump 226 can be used for this purpose.
Two standoffs or stabilizers 228, 230 hold the fluid sampling tool
170 in place as the probes 218, 220 press against the borehole wall
to receive fluid. In an embodiment, die probes 218, 220 and
stabilizers 228, 230 are retracted when the tool is in motion and
are extended to gather samples of fluid from the formation.
[0026] With additional reference to FIG. 3, the multi-chamber
sections 214 include multiple sample chambers 230, While FIGS. 2
and 3 show the multi-chamber sections 214 having three sample
chambers 230, it will be understood that the multi-chamber sections
214 can have any number of sample chambers 230 and may in fact be
single chamber sections. In some embodiments, the sample chambers
230 may be coupled to the channel 206 through respective chamber
valves 320, 325, 330. Formation fluid can be directed from the
channel 206 to a selected one of the sample chambers 230 by opening
the appropriate one of the chamber valves 320, 325, 330. The valves
320, 325, 330 may be configured such that when one of the chamber
valves 320, 325, 330 is open the others are closed.
[0027] In some embodiments, the multi-chamber sections 214 may
include a path 335 from the channel 206 to the annulus 160 through
a valve 340. Valve 340 may be open during the draw-down period when
the fluid sampling tool 170 is clearing mud cake, drilling mud, and
other contaminants into the annulus before clean formation fluid is
directed to one of the sample chambers 230. A check valve 345 may
prevent fluids from the annulus 160 from flowing hack into the
channel 206 through the path 335. As such, the mufti-chamber
sections 214 may include a path 350 from the sample chambers 230 to
the annulus 160.
[0028] FIG. 4 illustrates a cross-sectional view an example
embodiment of a sample chamber 230 lined with a coating 400 of a
material that can reversibly sorb a target component. As
illustrated, the coating 400 may be disposed on inner surfaces 402
of chamber walls 404. Sample chamber 230 may be any suitable
chamber for use in a fluid sampling tool (e.g., fluid sampling tool
170 on FIGS. 1A, 11B, and 2). In some embodiments, sample chamber
230 may have a fixed volume. For example, the sample chamber 230
may have a fixed volume of from about 0.1 milliliters to about 1
liter. Alternatively, the sample chamber 230 may have a fixed
volume of from about 1 milliliters to about 1 liter. In some
embodiments, the sample chamber 230 may be configured for obtaining
micro-samples, i.e., volumes of less than 1 milliliter. For
example, the sample chamber 230 may have a fixed volume of from
about 10 milliliters to about 1 milliliters. One of ordinary skill
in the art, with the benefit of this disclosure, should be able to
select an appropriate sample chamber 230 and size thereof for a
particular application.
[0029] As illustrated, the coating 400 may line the sample chamber
230. The coating 400 may include any of a variety of suitable
materials capable of reversibly sorbing a target component, such as
H2S, mercury, or carbon dioxide, whether by absorption or
adsorption. Non-limiting examples of suitable materials may
include, but are not limited to, gold, silver, nickel, platinum,
and combinations thereof. In some embodiments, gold may be suitable
for reversible absorption of target component, such as H2S and
mercury. In some embodiments, nickel and/or platinum may be
suitable for reversible absorption of H2S and/or mercury. One of
ordinary skill in the art, with the benefit of this disclosure,
should be able to select an appropriate material for the coating
400 based on a number of factors, including the particular target
component of interest.
[0030] The coating 400 on the chamber walls 404 may have any
suitable thickness. For example, the coating 400 may have a
thickness of about 10 nm to about 100 microns. In some embodiments,
the coating 400 may have a thickness of about 0.1 micron to about 1
micron or about 10 microns to about 100 microns. One of ordinary
skill in the art, with the benefit of this disclosure, should be
able to select an appropriate thickness for the coating 400 based
on a number of factors, including the particular target component
of interest and surface area.
[0031] The coating 400 may be applied to the chambers walls 404
using any suitable technique. Suitable techniques may include any
of a variety of different techniques for depositing a coating onto
a substrate, including, but not limited to thin-film deposition
techniques, such as atomic layer deposition, physical vapor
deposition, and chemical vapor deposition. One or ordinary skill in
the art, with the benefit of this disclosure, should be able to
select an appropriate technique for application of the coating
400.
[0032] It should be understood that the surface area of the coating
400 available for the target component may provide an upper limit
on the amount of the target component that can be quantified. In
other words, the fluid sample may, in some embodiments, contain
more of the target component than can be sorbed by the coating 400.
Accordingly, the surface of the coating 400 may be selected so that
a sufficient quantity of target component can be measured to
provide desirable information.
[0033] In some embodiments, the surface-to-volume ratio of the
coating 400 and or the chamber walls 404 may be maximized, for
example, to provide additional surface area for sorption of the
target component. In this manner, the coating 400 and/or the
chamber walls 404 may be configured to effective sorption of
different concentrations of the target component. In some
embodiments, the surface-to-volume ratio of the coating 400 may be
maximized. In some embodiments, the surface-to-volume ratio of the
chamber walls 404 may be maximized. In some embodiments, the
surface-to-volume ratio of the coating 400 and the chamber walls
404 may be maximized. Any of a variety of techniques may be applied
to the coating 400 and/or chamber walls 404 for maximization of the
surface-to-volume ratio. Suitable examples of the coating 400
and/or chamber walls 404 with increased surface-to-volume ratio may
include creation of a porous or structure coating that maximizes
surface-to-volume ratio. Examples of suitable techniques for
maximization of the surface-to-volume ratio may include, but are
not limited to, lithograph techniques, such as etching, anodizing,
or patterning. Specific examples of suitable lithograph techniques
may include, but are not limited to, electro-chemical anodization,
semiconductor lithography, and electron-beam lithography. In
addition to lithographic techniques applied to the chamber walls
404 and/or the coating 400 after deposition, techniques may also be
used to maximize the surface-to-volume ratio during of the coating
400 application, including nanotube deposition and nanoparticle
deposition. In addition to the above mentioned techniques, the
coating material may be deposited in such a way as to create a
highly porous material coating.
[0034] FIG. 5A illustrates an enlarged cross-sectional view of a
sample chamber 230 showing an example embodiment of a porous
coating 500. The porous coating 500 may provide, for example, an
increased surface-to-volume ratio as compared to non-porous
coatings. As illustrated, the porous coating 500 may be deposed on
the inner surfaces 402 of the chamber walls 404. While the porous
coating 500 is shown with a random distribution of pores 502, it
should be understood that the structure and arrangement of the
pores 502 should depend on the particular application technique.
For example, a porous coating 500 be provided with the pores 502 in
a regular distribution (not shown).
[0035] FIG. 5B illustrates an enlarged cross-sectional view of a
sample chamber 230 showing an example embodiment of a structured
coating 504. The structured coating 504 may provide, for example,
an increased surface-to-volume ratio as compared to non-patterned
coating. As illustrated, the structured coating 504 may be deposed
on the inner surfaces 402 of the chamber walls 404.
[0036] In some embodiments, a protective coating (not shown) may be
applied to sample chamber 230 and/or to other components of the
fluid sampling tool 170. For example, the protective coating may be
applied on the chamber walls 404 underneath the coating 400 such
that the coating 400 may be backed by the protective coating. In
addition, the protective coating may be applied to other components
of the fluid sampling tool 170, such as o-rings, seals, inlet lines
(e.g., channel 206 on FIG. 2), inlet valves (e.g., chamber valves
320, 325, 330 on FIG. 3). The protective coating may include any
suitable material that is resistant to target component, for
example, does not readily adsorb, absorb, or otherwise react to the
target component. Suitable materials may include, but are not
limited to, aluminum oxide and beryllium oxide, which are both
resistant to H2S. One or ordinary skill in the art, with the
benefit of this disclosure, should recognize that the specific
material for the protective coating should depend on a number of
factors, including the particular target component.
[0037] FIG. 6 illustrates an example of a test system 600 for
target component measurement. As illustrated, the test system 600
may include a chamber housing 602, a fluid analyzer 604, a vacuum
pump 606, and a processor 608. Chamber housing 602 may include a
chamber receptacle 610 for receiving the sample chamber 230. Sample
chamber 230 may contain, for example, a fluid sample of a formation
fluid. In some embodiments, the fluid sample may be evacuated from
the sample chamber 230 prior to use of test system 600. As
previously described, the fluid sample may contain a target
component. It may be desired to quantity the concentration of the
target component in the fluid sample. In some embodiments, test
system 600 may be used for measurement and quantification of the
target component in the fluid sample.
[0038] In some embodiments, the chamber housing 602 may receive the
sample chamber 230 in the chamber receptacle 610. As previously
described, the target component may have been sorbed by the coating
(e.g., coating 400 on FIG. 4) lining the sample chamber 230. The
chamber housing 602 may be operable to desorb the target component
from the coating. By way of example, the chamber housing 602 may
include a heating element 612. In some embodiments, the heating
element 612 may confirm electrical energy into heat. The heat from
the heating element 612 may heat the chamber housing 602 such that
the target component may be desorbed from the chamber housing 602.
While the heating element 612 is shown, it should be understood
that the present techniques are intended to encompass other
techniques for desorption of the target component from the chamber
housing 602. For example, the target component may be chemically
stripped from the chamber housing 602.
[0039] Test system 600 may further include a fluid analyzer 604 for
analyzing the target component after desorption from the chamber
housing 602. In the illustrated embodiment, a channel 614 provides
fluid communication between the fluid analyzer 604 and the sample
chamber 230. Chamber housing 602 may be opened (or otherwise)
accessed so that the desorbed target component in the chamber
housing 602 can be provided into the fluid analyzer 604 for
analysis. As illustrated, a vacuum pump 606 may be used, for
example, to create a suction that drives the fluid sample with the
desorbed target component from the chamber housing 602 to the fluid
analyzer 604. Fluid analyzer 604 may use any of a variety of
suitable analysis techniques for analyzing the fluid sample to
quantify concentration of the target component. Suitable analysis
techniques may include, but are not limited to, gas chromatography,
mass spectrometry, and optical sensors.
[0040] Test system 600 may further include processor 608. The
processor 608 may include any suitable device for processing
instructions, including, but not limited to, a microprocessor,
microcontroller, embedded microcontroller, programmable digital
signal processor, or other programmable device. The processor 608
may also, or instead, be embodied in an application specific
integrated circuit, a programmable gate array, programmable array
logic, or any other device or combinations of devices operable to
process electric signals. The processor 608 may be communicatively
coupled to the fluid analyzer 604. The connection between the fluid
analyzer 604 and the processor 608 may be a wired connection or a
wireless connection, as desired for a particular application.
[0041] In some embodiments, the processor 200 can be configured to
receive inputs from the fluid analyzer 604, for example, to
determine a concentration of the target component in the fluid
sample. The fluid analyzer 604, for example, may measure a total
quantity (e.g., volume, moles, etc.) of the target component. Since
of a total volume of the fluid sample in the sample chamber is
known, the concentration of the target component in the fluid
sample can then be readily determined with the total quantify of
the target component.
[0042] In some embodiments, target component measurements may be
extrapolated to reservoir conditions. Extrapolation may be
performed, for example, using measurements of the target component
from more than one sample chamber 230. The fluid sample may be
acquired in each of the more than one sample chamber 230 downhole
at during the same pump out or at different times. Any suitable
technique may be used for extrapolating the target component
measurement to reservoir conditions, including, but not limited to,
equations of state and geodynamic modeling, among others.
[0043] Accordingly, this disclosure describes methods and systems
for capture and measurement of a target component. Without
limitation, the systems and methods may further be characterized by
one or more of the following statements:
[0044] Statement 1. A fluid sampling tool for sampling fluid from a
subterranean formation may be provided. The fluid sampling tool may
include a sample chamber having a fluid inlet, wherein the sample
chamber is lined with a coating of a material that can reversibly
hold a target component.
[0045] Statement 2. The fluid sampling tool of statement 1, wherein
the fluid sampling tool further includes a probe that is extendable
to engage the subterranean formation from a wellbore, a pump
coupled to the probe for pumping fluid from the subterranean
formation, wherein the sample chamber is coupled to the pump for
receiving a fluid sample pumped from the subterranean formation
through the probe.
[0046] Statement 3. The fluid sampling tool of statement 1 or 2,
further including more than one of the sample chamber.
[0047] Statement 4. The fluid sampling tool of any preceding
statement, wherein the sample chamber includes a sample fluid
including the target component.
[0048] Statement 5, The fluid sampling tool of any preceding
statement, wherein the target component includes at least one
component selected from the group consisting of hydrogen sulfide,
mercury, carbon dioxide, and combinations thereof, and wherein the
material includes at least one material selected from the group
consisting of gold, aluminum oxide, nickel, platinum, and
combinations thereof.
[0049] Statement 6. The fluid sampling tool of any preceding
statement, wherein the coating and/or one or more walls of the
sample chamber were treated to increase a surface-to-volume ratio
of the coating.
[0050] Statement 7. The fluid sampling tool of statement 6, wherein
coating and/or the one or more walls were treated with a treatment
including at least one lithographic technique selected from the
group consisting of etching, anodizing, patterning, and
combinations thereof.
[0051] Statement 8. The fluid sampling tool of any preceding
statement, wherein at least one surface of the fluid sampling tool
is coated with a protective coating that is resistant to the target
component.
[0052] Statement 9. The fluid sampling tool of any preceding
statement, wherein the coating is a porous or structured
coating.
[0053] Statement 10. The fluid sampling tool of any preceding
statement, wherein the coating includes gold, wherein the target
component includes hydrogen sulfide, and wherein at least one
surface of the fluid sampling tool is coated with a protective
coating of aluminum oxide that is resistant to the target
component.
[0054] Statement 11. The fluid sampling tool of any preceding
statement, wherein the material is backed with an inert material to
the target component.
[0055] Statement 12. The fluid sampling tool of statement 11,
wherein the inert material includes aluminum oxide, beryllium
oxide, or a combination thereof.
[0056] Statement 13. A method for sampling formation fluids may be
provided. The method may include inserting a sample chamber into a
wellbore, wherein the sample chamber is lined with a material that
can reversibly hold a target component. The method may further
include collecting a fluid sample in the sample chamber while
disposed in the wellbore such that the target component in the
fluid sample is at least partially sorbed by the material.
[0057] Statement 14. The method of statement 13, wherein at least
99% by volume of the target component in the fluid sample is sorbed
by the material.
[0058] Statement 15. The method of statement 13 or 14, further
including retrieving the sample chamber from the wellbore,
desorbing the target component from the material, and measuring a
quantity of the desorbed target component.
[0059] Statement 16. The method of statement 15, wherein the
desorbing includes heating the sample chamber.
[0060] Statement 17. The method statement 15 may further include
collecting one or more additional fluid samples in one or more
additional sample chambers while disposed in the wellbore, wherein
the one or more additional sample chambers are lined with the
material such that at least a portion of the target component
present in the one or more additional fluid samples is at least
partially sorbed by the material in the one or more additional
sample chambers. The method may further include retrieving the one
or more additional sample chambers from the wellbore. The method
may further include desorbing the target component from the
material in the one or more additional samples chambers. The method
may further include measuring a quantity of the desorbed component
from the one or more additional sample chambers. The method may
further include extrapolating the quantity of the desorbed
component from the one or more additional sample chambers and the
desorbed component from the sample chamber to a reservoir
concentration.
[0061] Statement 18, The method of any one of statements 13 to 17,
wherein the target component includes hydrogen sulfide and the
material includes gold, and wherein at least one surface of a fluid
sampling tool including the sample chamber is partially coated with
a protective coating that is resistant to the target component.
[0062] Statement 19. A test system for component measurement may be
provided. The test system may include a chamber housing including a
chamber receptacle for receiving a sample chamber. The test system
may further include a heating element disposed in the chamber
housing arranged to heat the sample chamber. The test system may
further include a fluid analyzer for measuring a desorbed component
from the sample chamber. The test system may further include a
vacuum pump in fluid communication with the chamber housing for
creating a suction to transfer the desorbed component from the
sample chamber to the fluid analyzer. The test system may further
include a processor operable to receive inputs from the fluid
analyzer to determine a concentration of the desorbed
component.
[0063] Statement 20. The system of statement 19, wherein the fluid
analyzer is selected from a mass spectrometer, a gas chromatograph,
an optical sensor, and combinations thereof.
[0064] The preceding description provides various embodiments of
the systems and methods of use disclosed herein which may contain
different method steps and alternative combinations of components.
It should be understood that, although individual embodiments may
be discussed herein, the present disclosure covers all combinations
of the disclosed embodiments, including, without limitation, the
different component combinations, method step combinations, and
properties of the system. It should be understood that the
compositions and methods are described in terms of "including,"
"containing," or "including" various components or steps, the
compositions and methods can also "consist essentially of" or
"consist of" the various components and steps. Moreover, the
indefinite articles "a" or "an," as used in the claims, are defined
herein to mean one or more than one of the element that it
introduces.
[0065] For the sake of brevity, only certain ranges are explicitly
disclosed herein. However, ranges from any lower limit may be
combined with any upper limit to recite a range not explicitly
recited, as well as, ranges from any lower limit may be combined
with any other lower limit to recite a range not explicitly
recited, in the same way, ranges from any upper limit may be
combined with any other upper limit to recite a range not
explicitly recited. Additionally, whenever a numerical range with a
lower limit and an upper limit is disclosed, any number and any
included range falling within the range are specifically disclosed.
In particular, every range of values (of the form, "from about a to
about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be
understood to set forth every number and range encompassed within
the broader range of values even if not explicitly recited. Thus,
every point or individual value may serve as its own lower or upper
limit combined with any other point or individual value or any
other lower or upper limit, to recite a range not explicitly
recited.
[0066] Therefore, the present embodiments are well adapted to
attain the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, and may be modified and practiced in different
but equivalent manners apparent to those skilled in the art having
the benefit of the teachings herein. Although individual
embodiments are discussed, the disclosure covers all combinations
of all of the embodiments. Furthermore, no limitations are intended
to the details of construction or design herein shown, other than
as described in the claims below. Also, the terms in the claims
have their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee. It is therefore evident that the
particular illustrative embodiments disclosed above may be altered
or modified and all such variations are considered within the scope
and spirit of those embodiments. If there is any conflict in the
usages of a word or term in this specification and one or more
patent(s) or other documents that may be incorporated herein by
reference, the definitions that are consistent with this
specification should be adopted.
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