U.S. patent application number 11/767576 was filed with the patent office on 2008-12-25 for fluid level indication system and technique.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Dylan H. Davies.
Application Number | 20080314142 11/767576 |
Document ID | / |
Family ID | 39637842 |
Filed Date | 2008-12-25 |
United States Patent
Application |
20080314142 |
Kind Code |
A1 |
Davies; Dylan H. |
December 25, 2008 |
FLUID LEVEL INDICATION SYSTEM AND TECHNIQUE
Abstract
A technique that is usable with a well includes disposing a
distributed temperature sensor in a conduit that traverses a region
of the well. The region contains at least two different well fluid
layers. The technique includes circulating a fluid through the
conduit and using the distributed temperature sensor to observe at
least one temperature versus depth profile of the fluid. Based on
the observation, the depth of a boundary of at least one of the
well fluid layers is determined.
Inventors: |
Davies; Dylan H.;
(Painswick, GB) |
Correspondence
Address: |
SCHLUMBERGER RESERVOIR COMPLETIONS
14910 AIRLINE ROAD
ROSHARON
TX
77583
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
39637842 |
Appl. No.: |
11/767576 |
Filed: |
June 25, 2007 |
Current U.S.
Class: |
73/295 ;
374/E11.015 |
Current CPC
Class: |
E21B 47/047 20200501;
G01K 11/32 20130101; E21B 47/103 20200501 |
Class at
Publication: |
73/295 |
International
Class: |
G01F 23/00 20060101
G01F023/00 |
Claims
1. A method usable with a well, comprising: disposing a distributed
temperature sensor in a conduit that traverses a region of the
well, the region containing at least two different well fluid
layers and the distributed temperature sensor indicating a
temperature versus depth profile; circulating a fluid through the
conduit; controlling the circulation to cause the temperature
versus depth profile to indicate at least one boundary of the well
fluid layers; based on the indication, determining the depth of at
least one boundary of said at least one boundary.
2. The method of claim 1, wherein the act of controlling the
circulation comprises pumping the fluid from the surface of the
well using a pump located at the surface.
3. The method of claim 1, wherein the act of controlling the
circulation comprises pumping the fluid from a downhole
location.
4. The method of claim 1, wherein the act of determining comprises
identifying at least one discontinuity in the temperature versus
depth profile.
5. The method of claim 1, wherein the act of controlling the
circulation comprises halting the circulation of the fluid in the
region, and the temperature versus depth profile is indicative of a
relaxation of the temperature versus depth profile while the
circulation of the fluid is halted.
6. The method of claim 1, wherein the act of controlling the
circulation allows the temperature versus depth profile to reach
steady state while the fluid is being circulated.
7. The method of claim 1, wherein the act of controlling the
circulation comprises varying a rate of the circulating; and the
act of determining comprises observing the temperature versus depth
profile for different circulation rates of the fluid.
8. The method of claim 1, wherein the act of determining comprises
observing the temperature versus depth profile during a relaxation
period in which the fluid is not being circulated and in a second
period in which the temperature versus depth profile is in steady
state and the fluid is being circulated.
9. A system usable with a well, comprising: a tubing to traverse a
region of the well, the region containing at least two different
well fluid layers; a distributed temperature subsystem comprising a
distributed temperature sensor disposed in the tubing to indicate a
temperature versus depth profile; and a pump to circulate a fluid
through the tubing, wherein the circulation of the fluid is
controlled to cause the temperature versus depth profile to
indicate the boundaries of the fluid layers, and the distributed
temperature subsystem observes the depth of at least one of the
boundaries based on the indication from the temperature versus
depth profile.
10. The system of claim 9, wherein the pump is located at the
surface of the well.
11. The system of claim 9, wherein the pump comprises a pump
located downhole in the well.
12. The system of claim 9, wherein the temperature versus depth
profile contains at least one discontinuity that identifies the
characteristic.
13. The system of claim 9, wherein the pump is adapted to halt the
circulation of the fluid in the tubing so that the temperature
versus depth profile undergoes a relaxation period while the fluid
is halted and indicates the characteristic during the
relaxation.
14. The system of claim 9, wherein the pump is adapted to circulate
the fluid to allow the temperature versus depth profile to reach
steady state.
15. The system of claim 9, wherein the pump is adapted to vary a
rate at which the fluid is circulated in the tubing and the
subsystem is adapted to obtain multiple temperature versus depth
profiles, with each temperature versus depth profile being
associated with a different one of the flow rates.
16. The system of claim 15, wherein the subsystem is adapted to
combine the multiple temperature versus depth profiles to indicate
the depth.
17. The system of claim 9, wherein the pump is adapted to, in a
relaxation test, circulate the fluid through the tubing and then
halt the fluid, and in a steady state test continuously circulate
the fluid, and the subsystem is adapted to combine results from the
relaxation test and the steady state test to identify the
depth.
18. The system of claim 9, wherein the distributed temperature
sensor is retrievable from the well.
19. The system of claim 18, wherein the sensor comprises an optical
fiber.
20. The system of claim 9, further comprising: a non DTS-based
sensor located in the region.
21. The system of claim 20, wherein the non DTS-based sensor
comprises a pressure sensor.
22. A system comprising: a tubing to traverse a region of a
container, the region containing at least two different fluid
layers; a pump to circulate a fluid through the tubing; and a
subsystem comprising a distributed temperature sensor disposed in
the tubing to indicate a temperature versus depth profile, the
subsystem adapted to observe the temperature versus depth profile
in response to the circulation of the fluid such that the
temperature versus depth profile indicates a characteristic
associated with at least one of the fluid layers.
23. The system of claim 22, wherein the pump is adapted to
circulate the fluid through the tubing and subsequently halt the
circulation of fluid, and the subsystem is adapted to observe
relaxation of the temperature versus depth profile while the fluid
is halted to generate an indication of the characteristic.
24. The system of claim 22, wherein the pump is adapted to
continuously circulate the fluid through the tubing such that the
temperature versus depth profile reaches steady state, and the
subsystem is adapted to in a steady state test generate an
indication of the temperature versus depth profile while the fluid
is being circulated.
Description
BACKGROUND
[0001] The invention generally relates to a fluid level indication
system and technique.
[0002] In oil fields it is typically important to know the levels
of the fluids in the reservoir and around wells, and in particular,
it may be important to know the depths of the interfaces between
the gas, oil and water layers. Such knowledge is particularly
important in secondary and tertiary recovery systems, for example,
in steam flooding applications in heavy oil reservoirs.
[0003] Traditionally, the depths of the interfaces between the
fluid levels are determined using pressure measurements. For
example, one approach involves using a single pressure sensor,
which makes a series of pressure measurements at multiple depths.
The measured pressure is plotted against the depth. In each of the
gas, oil and water layers, the pressure gradient is constant and
proportional to the density of the fluid. The depths of the fluid
layer interfaces, or boundaries, are identified by the
intersections of the pressure gradient lines. The above-described
technique of identifying the interface depths using a pressure
sensor typically works well when carried out in an intervention in
the well using, for example, a wireline-deployed tool.
[0004] For purposes of permanently monitoring the depths of the
fluid interfaces, an array of pressure sensors may be placed across
the gas, oil and water layers. In this regard, the pressure
gradients may be plotted and the analysis that is set forth above
may be applied. If the depths of the interfaces change over time, a
large number of pressure sensors may be required to accurately
assess the interface depths. A large number of pressure sensors may
also be required if the initial positions of the interfaces are
unknown or uncertain. However, several challenges may arise with
the use of a large number of pressure sensors, such as challenges
related to compensating the pressure readings for sensor offset and
drift. Furthermore, the cost of an array of pressure sensors can be
high and prohibitive.
[0005] Downhole distributed temperature sensing (DTS) involves the
use of a sensor that indicates a temperature versus depth
distribution in the downhole environment. DTS typically is used to
identify and quantify production from different
injection/production zones of a well.
[0006] For example, in a technique called "hot slug tracking," DTS
may be used to identify the permeable zones in a water injector
well where injected fluid enters the formation. The permeable zones
typically cannot be identified by DTS during normal injection.
However, by shutting off injection and allowing the water in the
tubing or casing above the injection zone to be heated up towards
the geothermal gradient, a heated "slug" may be created. When the
injection is re-started, the hot slug may be tracked versus time
using the DTS measurements to identify the permeable zones.
SUMMARY
[0007] In an embodiment of the invention, a technique that is
usable with a well includes disposing a distributed temperature
sensor in a conduit that traverses a region of the well. The region
contains at least two different well fluid layers. The technique
includes circulating a fluid through the conduit and using the
distributed temperature sensor to observe at least one a
temperature versus depth profile of the fluid. Based on the
observation, the depth of a boundary of at least one of the well
fluid layers is determined.
[0008] In another embodiment of the invention, a system that is
usable with a well includes a distributed temperature sensor
subsystem, a tubing and a pump. A distributed temperature sensor of
the distributed temperature sensor subsystem is disposed in the
tubing, and the tubing traverses a region of the well, which
contains at least two different well fluid layers. The pump
circulates a fluid through the tubing; and the distributed
temperature subsystem observes at least one temperature versus
depth profile of the fluid such that said at least one temperature
versus depth profile indicates the depth of a boundary of at least
one of the well fluid layers.
[0009] In yet another embodiment of the invention, a system
includes a tubing, a pump and a subsystem. The tubing traverses a
region of a container, which contains at least two different fluid
layers, and a distributed temperature subsystem is disposed in the
tubing. The pump circulates a fluid through the tubing, and the
subsystem observes a temperature versus depth profile of the fluid
such that the temperature versus depth profile indicates a
characteristic associated with at least one of the fluid
layers.
[0010] Advantages and other features of the invention will become
apparent from the following drawing, description and claims.
BRIEF DESCRIPTION OF THE DRAWING
[0011] FIG. 1 is a flow diagram generally depicting a technique to
use a distributed temperature sensor to identify a characteristic
of at least one well fluid layer according to an embodiment of the
invention.
[0012] FIG. 2 is a schematic diagram of a well according to an
embodiment of the invention.
[0013] FIG. 3 is a flow diagram depicting a technique to identify a
characteristic of at least one well fluid layer based on
temperature relaxation according to an embodiment of the
invention.
[0014] FIGS. 4 and 5 are illustrations of temperature versus depth
profiles obtained by the distributed temperature sensor at
different times according to different embodiments of the
invention.
[0015] FIG. 6 is a flow diagram depicting a technique to use a
distributed temperature sensor to identify a depth of a boundary of
at least one well fluid layer using a steady state temperature
measurement technique according to an embodiment of the
invention.
[0016] FIG. 7 is a flow diagram depicting a technique to identify a
depth of at least one well fluid layer boundary using a combination
of distributed temperature sensing and different flow rates
according to an embodiment of the invention.
[0017] FIG. 8 is a flow diagram depicting a technique to use a
combination of relaxation and steady state distributed temperature
sensing techniques to identify a depth of at least one well fluid
layer boundary according to an embodiment of the invention.
[0018] FIG. 9 is a flow diagram depicting a technique to use a
distributed temperature sensor to identify a characteristic of at
least one fluid layer that is present in a container according to
an embodiment of the invention.
DETAILED DESCRIPTION
[0019] In accordance with embodiments of the invention described
herein, the depths of different well fluid layer interfaces
(interfaces between oil, gas and water layers, as examples) are
determined using one or more distributed temperature sensing (DTS)
measurements. Each DTS measurement reveals a temperature versus
depth distribution, or profile, of a fluid that is contained in a
conduit (pipe, tubing, or control line, as just a few examples of a
"conduit") that traverses the well fluid layers of interest. The
temperature versus depth profile, in turn, indicates the interface
depths.
[0020] As set forth by way of specific examples herein, the DTS
measurements may be conducted in connection with two different
types of tests: 1.) a first test (called a "relaxation test"
herein) in which the measured temperature versus depth profile is
used to observe the fluid's temperature relaxation after
circulation of the fluid in the conduit has been halted; and 2.) a
second test (called a "steady state test" herein) in which the
temperature versus depth profile is used to observe the fluid's
steady state temperature while the fluid is being continuously
circulated in the conduit. The relaxation temperature versus depth
profile and the steady state temperature versus depth profile each
reveals the locations (i.e., depths) of the well fluid interfaces,
as further described below.
[0021] To generalize, FIG. 1 depicts a technique 10 that may be
used in accordance with embodiments of the invention. Pursuant to
the technique 10, a distributed temperature sensor is deployed
(block 14) in a conduit that traverses a region of interest of a
well, and fluid is communicated through the conduit, as depicted in
block 18. The distributed temperature sensor is used to observe
(block 22) the temperature versus depth profile of the fluid; and
based on the observed temperature profile, the depth of at least
one well fluid layer boundary in the region of interest may be
identified, pursuant to block 26.
[0022] FIG. 2 depicts an exemplary well 50, which uses a DTS-based
system 100 (Sensa's DTS-800 system, for example) in accordance with
embodiments of the invention. For purposes of obtaining a
temperature versus depth profile, the well 50 includes a downhole
DTS subsystem, which includes a distributed temperature sensor 87
(an optical fiber, for example) that is disposed in a conduit 80 (a
control line, as an example). In accordance with some embodiments
of the invention, the distributed temperature sensor 87 may be
placed inside a small control line (not depicted in FIG. 2), which
extends downhole inside the conduit 80. In this regard, the small
control line may be filled with an inert gas (nitrogen, for
example) or fluid (silicone oil, for example) for purposes of
protecting the distributed temperature sensor 87. More
specifically, if the distributed temperature sensor 87 is an
optical fiber, the fiber when placed in a fluid, such as water, may
degrade relatively quickly. Therefore, by disposing the optical
fiber inside a small control line that extends inside the conduit
80 and filling this conduit with the inert gas, the lifetime of the
optical fiber is extended.
[0023] The conduit 80 extends downhole in a wellbore 60 and
traverses a region of the well 50, which contains various fluid
layers 70 such as exemplary gas 70a, oil 70b and water 70c layers.
As shown in FIG. 2, the conduit 80 is U-shaped in that the fluid
flows through the conduit 80 downhole into the well 50 and returns
uphole to the well surface. More specifically, the conduit 80
receives (at an inlet 82) a fluid flow, which is produced by a
surface pump 96. The fluid flows from the inlet 82, through the
fluid layers 70 and passes through a U-shaped bottom 84 of the
conduit 80. At this point the fluid returns to the surface of the
well 50 and thus, passes through the layers 70 back to an outlet 86
of the conduit 80, which is located at the surface of the well. At
the surface, the fluid enters a reservoir 94, and from the
reservoir 94 the fluid returns via the pump 96 back into the well
50.
[0024] Thus, the conduit 80 forms a loop for circulating a fluid
through the well fluid layers 70. Depending on the particular
embodiment of the invention, the fluid in the conduit 80 may be
water, toluene or hydraulic oil, as just a few examples.
[0025] In accordance with some embodiments of the invention, the
sensor 87 may be retrievable from the well 50. For example, in
embodiments of the invention, in which the sensor 87 is an optical
fiber, the fiber may be pumped into position in the conduit 80. The
overall physical condition of the optical fiber may potentially
degrade over time. Therefore, it may become desirable to remove the
optical fiber from the conduit 80 (by pumping) and pump a
replacement optical fiber into the conduit 80.
[0026] It is noted that the well 50 is merely an example of one out
of many different types of wells that may use the techniques and
systems that are described herein. In this regard, although FIG. 2
depicts a vertical wellbore 60, it is understood that the systems
and techniques that are described herein may be applied to
deviated, lateral, or horizontal wellbore sections. Additionally,
the wellbore 60 may be cased or uncased, depending on the
particular embodiment of the invention. Furthermore, the well 50
may be a subterranean or subsea well, depending on the particular
embodiment of the invention. Thus, many variations are
contemplated, all of which fall within the scope of the appended
claims.
[0027] The distributed temperature sensor 87 may be disposed in the
downstream flowing portion of the conduit (as depicted in FIG. 2)
or the upstream flowing portion of the conduit 80, depending on the
particular embodiment of the invention. As another variation, in
accordance with some embodiments of the invention, the distributed
temperature sensor 87 of FIG. 2 may be installed in a double-ended
configuration, in which the sensor 87 extends in a U configuration
from the inlet 82 to the outlet 86 of the conduit 80. The
distributed temperature sensor 87 may be deployed with the conduit
80 (and thus, may be installed downhole with the conduit 80) or may
be subsequently pumped into the conduit 80 after the conduit 80 is
installed downhole, depending on the particular embodiment of the
invention. For embodiments of the invention in which the
distributed temperature sensor 87 is an optical fiber, the sensor
87 may be optically coupled to a DTS measurement system 100, which
may be located at the surface of the well 50.
[0028] By activating the pump 96, the temperature profile of the
fluid in the loop (i.e., in the conduit 80) can be changed, as
fluid from a region at one temperature is pumped to a region at a
different temperature. When pumping ceases, the temperature of the
fluid relaxes to the new local temperature. Since the efficiency of
heat transfer is different for different fluids, the relaxation
rates will differ from zone to zone. The distributed temperature
profile will change with time and will have distinct regions that
are separated by boundaries. These boundaries are located at the
depths of the interfaces between the different fluids in the
well.
[0029] As a more specific example, FIG. 3 depicts a technique 150,
which is an example of the relaxation test, in accordance with some
embodiments of the invention. Pursuant to the technique 150, a
distributed temperature sensor is used (block 152) to determine an
initial steady state profile of region of interest prior to
circulation of fluid. The fluid is circulated (block 154) in a
conduit (e.g., the conduit 80 of FIG. 2), which traverses a region
of the well that contains well fluid layers. Circulation of the
fluid is then halted (block 158), e.g., the pump 96 is momentarily
turned off. At this point, the temperature versus depth profile (as
indicated by the DTS system) undergoes a temperature relaxation, in
that the local temperature of the fluid in the conduit varies with
the thermal properties (thermal capacity and thermal conductivity)
of the surrounding environment.
[0030] More specifically, FIG. 4 depicts an illustration 200 of
three exemplary temperature versus depth profiles 204, 210 and 220,
which are associated with different stages of the relaxation test.
Prior to the pumping of fluid, the temperature versus depth profile
is similar to the profile 220. While the fluid circulates in the
conduit 80 (FIG. 2) at a sufficiently fast rate, the temperature
versus depth profile resembles the exemplary profile 204, which is
generally linear. After the pump is turned off, the relatively cool
fluid is heated by the surrounding fluid layers, thereby changing
the temperature versus depth profile, as the local temperatures
rise. Because the well fluid layers 70 have different thermal
conductivities and capacities, the rate of warming is locally
different in the different layers 70 during the warming, or
relaxation period, as illustrated by exemplary profile 210.
[0031] Due to the differences in the thermal properties, the
profile 210 is discontinuous at each well fluid layer interface.
Thus, the boundary between the upper gas layer 70a and the middle
oil layer 70b, according to the temperature profile 210, occurs at
depth D.sub.1; and the interface between the middle oil layer 70b
and the lower water layer 70c occurs at a depth D.sub.2. The arrows
adjacent the profile 210 indicate the direction that the profile
210 moves over time.
[0032] Eventually, the transient effects, which are present during
the relaxation period pass so that the fluid in the loop warms up
to the temperature of the surrounding fluid. At this point, the
temperature versus depth profile resembles the exemplary profile
220, which is generally linear throughout all of the well fluid
layers 70 and represents the geothermal gradient (unless secondary
tertiary recovery schemes such as steam flooding is used in which
case the profile is not linear). When thermal equilibrium around
the loop has been established, the above-described process may be
repeated. Several relaxation temperature versus depth profiles may
be stacked for purposes of improving the overall signal-to-noise
ratio. The stacking of successive relaxation profiles is valid
because the fluid levels in a well may vary relatively slowly with
time.
[0033] Many variations are contemplated and are within the scope of
the appended claims. For example, in accordance with other
embodiments of the invention, the well may not have a reservoir at
the surface for purposes of storing the fluid that is circulated
through the conduit 80. In this regard, instead of pumping
relatively colder fluid from the surface of the well, relatively
warmer fluid may be pumped through the loop across the reservoir.
The warmer fluid may also be supplied, for example, by a surface
heating system or from a downhole pump. Thus, with circulation of
the fluid through the loop being halted, the local temperature of
the fluid cools (instead of being heated) as a function of the
thermal conductivities and capacities of the surrounding fluid
layers.
[0034] As a more specific example, FIG. 5 depicts an illustration
229 of exemplary temperature versus depth profiles 230, 234 and
240, which are associated with the fluid circulation, no fluid flow
and end of relaxation stages, respectively, when the warmer fluid
is circulated, in accordance with some embodiments of the
invention. As shown, when the pumping first ceases, the temperature
versus depth profile resembles the exemplary generally linear
profile 230. During the relaxation, the localized fluid temperature
is a function of the thermal properties of the local environment;
and as such, the temperature versus depth profile resembles the
exemplary profile 234, which has discontinuities that identify the
well fluid interfaces. Eventually at the end of the relaxation, the
temperature versus depth profile transitions to the exemplary
profile 240, which is generally linear.
[0035] It is noted that the systems that are described herein may
be used in applications in which steam is pumped into the reservoir
to reduce the viscosity of the oil. In this case, the initial
temperature versus depth profile may not be linear but instead may
exhibit an increase in temperature higher up in the well.
Nevertheless, a change in temperature on pumping the fluid and a
relaxation to the initial profile are still revealed. Irrespective
of the initial profile, the local rate of relaxation is dependent
on the thermal properties of the well fluid at the particular
depth.
[0036] The relaxation of the local temperature measured by DTS
depends on the local thermal conductivity (k) and the specific heat
capacity (cp) of the material surrounding the pipe in which the
sensor is contained. Faster relaxation occurs with higher thermal
conductivity and higher specific heat capacity of the surrounding
material; and therefore, in an approximation, the relaxation time
decreases with their product (k*cp). Table 1 depicts typical values
of thermal conductivity (k), specific heat capacity (cp) and their
product (k*cp) for water, typical oil, methane, steam and air.
TABLE-US-00001 TABLE 1 Water Oil Methane Steam Air Specific Heat
capacity 4.18 1.6-2.4 2.2-2.8 2 1.01 (cp) J g-1 K-1 Average cp 4.18
2 2.5 2 1.01 J g-1 K-1 Thermal Conductivity 0.55-0.67 0.15 0.03
0.016 0.024 (k) W K-1 m-1 Average k 0.61 0.15 0.03 0.016 0.024 W
K-1 m-1 Product (average 2.55 0.3 0.075 0.032 0.024 cp) * (average
k)
[0037] The product k*cp is approximately an order of magnitude
higher for water than for oil, which in turn is almost an order of
magnitude higher than for any of the gases (methane, steam, air).
This indicates that the location of the oil/water and gas/oil fluid
interfaces in a well may be identified by changes or
discontinuities in relaxation of the temperature versus depth
profile after pumping hotter or colder fluid across the
reservoir.
[0038] FIG. 6 depicts a steady state technique 250 in accordance
with an embodiment of the invention and may be used as an
alternative to the relaxation test or may be used in conjunction
with the relaxation test, as further described below. Unlike the
relaxation test, the steady state test involves taking a DTS
measurement while the fluid is circulating in the conduit 80. The
rate at which the fluid is being circulated in the conduit 80 (FIG.
2) is such that the observed temperature versus depth profile
contains discontinuities at the well fluid interfaces. More
specifically, pursuant to the technique 250, a distributed
temperature sensor is deployed (block 254) in a well to observe a
temperature versus depth profile in a region of interest. A
distributed temperature sensor is used (block 255) to determine an
initial steady state profile prior to the circulation of a fluid in
the conduit that contains the sensor. The fluid is then circulated
through a conduit that traverses a region of the well, which
contains well fluid layers, pursuant to block 258. The temperature
versus depth profile is then allowed to reach steady state,
pursuant to block 262. Based on the observed temperature versus
depth profile, the depth of at least one well fluid layer interface
is determined, pursuant to block 266.
[0039] Thus, instead of pumping fluid from a hotter or colder zone
and then stopping and measuring the temperature relaxation, the
pumping may instead be continuous. The temperature versus depth
profile in the loop reaches steady state when the local flow of
heat into and out of the loop is balanced. At steady state, there
is a discontinuity in the temperature versus depth profile for each
point where the loop crosses the boundary between two fluid
layers.
[0040] The advantages of the steady state test may include one or
more of the following, depending on the particular embodiment of
the invention. The steady state test allows data to be recorded
over a longer period; and the data may be stacked and averaged over
time, thereby giving greater temperature resolution and greater
sensitivity. This steady state test may possibly be easier to
automate than the relaxation test. The steady state test may
provide a more reliable identification of the interface depths when
there is a non-uniform temperature distribution with depth, such
as, for example, in steam flood wells where a hot gas layer may
overlay cooler oil and water zones. If there are conduction effects
in the loop, which may degrade the DTS measurement, the steady
state approach may be less susceptible to this degradation.
[0041] Referring to FIG. 7, variations of the above-described
steady state test may be performed in other embodiments of the
invention. For example, several steady state tests may be
performed, where a different circulation flow rate is used for each
test. Thus, pursuant to a technique 300, fluid may be circulated in
a conduit at a first flow rate (block 304), and the steady state
test may be used to obtain a corresponding temperature versus depth
profile, pursuant to block 308. If another profile is desired
(diamond 312), the flow rate is changed (block 316) before the
steady state test is used again to observe a corresponding
temperature versus depth profile, pursuant to block 308. After
several temperature versus depth profiles have been obtained, the
temperature versus depth profiles may be interpreted (block 320) to
determine the depth of at least one well fluid layer interface. The
generation of multiple temperature versus depth profiles may
provide a better interpretation of the positioning of the well
fluid layers and the corresponding interfaces.
[0042] As an example of another embodiment of the invention,
referring to FIG. 8, a technique 360 may include using both the
relaxation (block 364) and steady state (block 368) tests to
determine the depth of at least one well fluid interface. Results
of the relaxation and steady state tests may then be combined to
identify one or more of the characteristics, pursuant to block 372.
Depending on the geometry and the nature of the fluid and
materials, the determination of different fluid interfaces may be
more sensitive to one test than to the other. Thus, by using the
combination of the steady state and relaxation tests, as outlined
in FIG. 8, the positioning of the well fluid layers and interfaces
may be more accurately determined.
[0043] In fields where steam flooding is employed, a Layer of fresh
water may be produced from condensed saline formation water. Thus,
there may be in effect, a fourth fluid layer. Knowledge of the
position of this layer may be useful. However, determining the
boundaries of the fresh and saline water layers may be more
difficult than the determination of the other boundaries because
the fresh and saline water have very similar thermal conductivities
and thermal capacities. Therefore, the use of a more sensitive
technique (such as the technique 300 (FIG. 7), for example) may be
able to distinguish the fresh and saline layers and the interface
in between.
[0044] Other systems and techniques are contemplated and are within
the scope of the appended claims. For example, referring to FIG. 9,
a technique 400 in accordance with some embodiments of the
invention includes deploying a distributed temperature sensor in a
container inside a conduit that extends through fluid layers
present in the container, pursuant to block 404. The distributed
temperature sensor is used (block 413) to determine the initial
steady state profile prior to the circulation of a fluid that is
contained in the conduit. The fluid is then communicated (forced
through by a pump, for example) through the conduit, pursuant to
block 412; and the distributed temperature sensor is used to
observe a temperature profile of fluid in the conduit, pursuant to
block 414. Thus, the particular profile observed depends on whether
the relaxation test, the steady state test or a combination thereof
is used. Based on the observed temperature profile, a
characteristic of at least one of the fluid layers is identified,
pursuant to block 416.
[0045] As another variation, in accordance with some embodiments of
the invention, the DTS system described herein may be combined with
other downhole sensor-based subsystems. In this regard, in
accordance with some embodiments of the invention, one or more
pressure sensors (as an example) may be disposed downhole in the
well to measure pressure(s) of the well fluid layer(s).
[0046] While the present invention has been described with respect
to a limited number of embodiments, those skilled in the art,
having the benefit of this disclosure, will appreciate numerous
modifications and variations therefrom. It is intended that the
appended claims cover all such modifications and variations as fall
within the true spirit and scope of this present invention.
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