U.S. patent application number 14/791792 was filed with the patent office on 2016-01-07 for matrix temperature production logging tool.
The applicant listed for this patent is CONOCOPHILLIPS COMPANY. Invention is credited to Kyle FRIEHAUF, Scott A. GRUBB.
Application Number | 20160003032 14/791792 |
Document ID | / |
Family ID | 55016674 |
Filed Date | 2016-01-07 |
United States Patent
Application |
20160003032 |
Kind Code |
A1 |
GRUBB; Scott A. ; et
al. |
January 7, 2016 |
MATRIX TEMPERATURE PRODUCTION LOGGING TOOL
Abstract
A matrix production logging tool for measuring the temperature
of produced fluids in a wellbore. Accurate production allocation to
the pathways between the oil/gas well and the reservoir provides
required data for the economic optimization of the techniques and
procedures used to complete future wells. The low maintenance tool
provides precise upstream, downstream and inflow temperature
measurements of produced fluids within the wellbore.
Inventors: |
GRUBB; Scott A.; (Houston,
TX) ; FRIEHAUF; Kyle; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
CONOCOPHILLIPS COMPANY |
Houston |
TX |
US |
|
|
Family ID: |
55016674 |
Appl. No.: |
14/791792 |
Filed: |
July 6, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62021441 |
Jul 7, 2014 |
|
|
|
Current U.S.
Class: |
73/152.12 |
Current CPC
Class: |
G01K 2213/00 20130101;
E21B 47/07 20200501; G01K 13/02 20130101; G01K 2013/026
20130101 |
International
Class: |
E21B 47/06 20060101
E21B047/06 |
Claims
1. A logging tool for use to determine temperature of produced
fluid flowing into or within a wellbore comprising: a. a core
structure; b. an arm extendibly and pivotally mounted to the core
structure, the arm is extended away from the core structure and is
near the inner surface of the wellbore, wherein the arm pivots in
one plane relative to the core structure; c. a data transfer device
connected to the core structure for receiving, processing and
storing data; and d. at least one temperature sensor attached to
the arm, wherein the temperature sensor is located at a tip of the
arm, wherein when the arm is extended away from the core structure
the temperature sensor is at or near the inner surface of the
wellbore.
2. The logging tool according to claim 1, wherein the temperature
sensor is selected from a group consisting of: resistive
temperature sensing devices, thermocouples, thermistors, infrared,
pressure of known encased fluid, laser or laser light within fiber
optics.
3. The logging tool according to claim 1, wherein the logging tool
includes a plurality of arms extendibly and pivotally mounted to
the core structure.
4. The logging tool according to claim 3, wherein the plurality of
arms include at least one temperature sensor.
5. The logging tool according to claim 3, wherein each arm includes
a plurality of temperature sensors.
6. The logging tool according to claim 1, wherein the arm includes
a plurality of temperature sensors.
7. The logging tool according to claim 1, wherein the data transfer
device transfers data from the wellbore to the surface.
8. A logging tool for use to determine temperature of produced
fluid flowing into or within a wellbore comprising: a. a core
structure; b. a plurality of arms extendibly and pivotally mounted
to the core structure, at least one arm is extended away from the
core structure and is near the inner surface of the wellbore,
wherein each arm pivots in one plane relative to the core
structure; c. a data transfer device connected to the core
structure for receiving, processing and storing data; and d. at
least one temperature sensor attached to each arm, wherein the
temperature sensor is located at a tip the arm, wherein when the
arm is extended away from the core structure the temperature sensor
is at or near the inner surface of the wellbore.
9. The logging tool according to claim 8, wherein the temperature
sensor is selected from a group consisting of: resistive
temperature sensing devices, thermocouples, thermistors, infrared,
pressure of known encased fluid, laser or laser light within fiber
optics.
10. The logging tool according to claim 8, wherein each arm
includes a plurality of temperature sensors.
11. The logging tool according to claim 8, wherein the data
transfer device transfers data from the wellbore to the surface.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a non-provisional application which
claims benefit under 35 USC .sctn.119(e) to U.S. Provisional
Application Ser. No. 62/021441 filed Jul. 7, 2014, entitled "MATRIX
TEMPERATURE PRODUCTION LOGGING TOOL," which is incorporated herein
in its entirety.
FIELD OF THE INVENTION
[0002] This invention relates to a matrix production logging tool
for measuring the temperature of produced fluids in a wellbore.
BACKGROUND OF THE INVENTION
[0003] Well logging surveys are often utilized in producing oil and
gas wells in order to determine the fraction of oil, gas and
unwanted water present in the production interval. This data along
with measurements of the fluid flow velocity, cross-section of the
well, pressure and temperature may be used to determine production
rates and other information from each zone of interest in the well.
Such data may be useful for optimizing the well's production, oil
recovery, and water shut-off, in order to achieve better reservoir
management and to reduce intervention costs. Future well's design
and completion methodology may also be improved due to available
surveys.
[0004] Such well logging surveys are performed by utilizing logging
tools. Generally, a logging tool comprises at least one sensor and
measures at least one parameter. For example, when measuring
temperature within a wellbore or temperature of the produced fluids
within a wellbore, a distributed temperature sensor can be mounted
to the logging tool.
[0005] Distributed temperature sensing (DTS) is a known method of
using an optical fiber to sense the temperature along the wellbore.
For example, an optical fiber positioned in a section of the
wellbore which intersects a producing formation or zone can be used
in determining where and how much of known fluids are being
produced as long as the fluid entering the wellbore measurably
alters the temperature of the fluid already flowing within the
wellbore. Temperature response of the produced fluids flowing
within the wellbore between inflow locations is used in
interpretations to estimate production along with wellbores length.
As DTS spatially averages temperature over approximately 1 meter
lengths it fails to provide precise measurements of the inflow
temperature of produced fluids.
[0006] Logging tools have also included spinner type flow meters
with attached temperature sensors which rotate when immersed within
a flow stream. However, this type of logging tool has had issues
with mechanical effectiveness. For example, the impeller of the
spinner operates on a bearing which wears and requires frequent
inspection and replacement to keep frictional effects from
influencing the measurements. Another disadvantage, which increases
logging time on the well, is that calibration must be done downhole
by making several extra logging runs at various logging speeds. In
reference to the fluid properties, the spinner speed is not only
affected by changes in the velocity of the fluid but also by
changes in the viscosity and density of the fluid.
[0007] Accurate production allocation to the pathways between the
oil/gas well and the reservoir provides required data for the
economic optimization of the techniques and procedures used to
complete future wells. A need exists for a reliable, low
maintenance tool to provide precise upstream, downstream and inflow
temperature measurements of produced fluids within the wellbore
that will be utilized to calculate production at each inflow
location.
SUMMARY OF THE INVENTION
[0008] In an embodiment, a logging tool for use to determine
temperature of produced fluid flowing into or within a wellbore
includes: a core structure; an arm extendibly and pivotally mounted
to the core structure, the arm is extended away from the core
structure and is near the inner surface of the wellbore, wherein
the arm pivots in one plane relative to the core structure; a data
transfer device connected to the core structure for receiving,
processing and storing data; and at least one temperature sensors
attached to the arm, wherein the temperature sensor is located at a
tip of the arm, wherein when the arm is extended away from the core
structure the temperature sensor is at or near the inner surface of
the wellbore.
[0009] In another embodiment, a logging tool for use to determine
temperature of produced fluid flowing into or within a wellbore
includes: a core structure; a plurality of arms extendibly and
pivotally mounted to the core structure, at least one arm is
extended away from the core structure and is near the inner surface
of the wellbore, wherein each arm pivots in one plane relative to
the core structure; a data transfer device connected to the core
structure for receiving, processing and storing data; and at least
one temperature sensor attached to each arm, wherein the
temperature sensor is located at a tip the arm, wherein when the
arm is extended away from the core structure the temperature sensor
is at or near the inner surface of the wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] The invention, together with further advantages thereof, may
best be understood by reference to the following description taken
in conjunction with the accompanying drawings in which:
[0011] FIG. 1 is a sectional view of the matrix temperature
production logging tool disposed within a wellbore, according to an
embodiment of the invention.
[0012] FIG. 2 is a simulated plot, according to an embodiment of
the invention.
DETAILED DESCRIPTION OF THE INVENTION
[0013] Reference will now be made in detail to embodiments of the
present invention, one or more examples of which are illustrated in
the accompanying drawings. Each example is provided by way of
explanation of the invention, not as a limitation of the invention.
It will be apparent to those skilled in the art that various
modifications and variations can be made in the present invention
without departing from the scope or spirit of the invention. For
instance, features illustrated or described as part of one
embodiment can be used in another embodiment to yield a still
further embodiment. Thus, it is intended that the present invention
cover such modifications and variations that come within the scope
of the appended claims and their equivalents.
[0014] As previously discussed, capturing the upstream, downstream
and inflow temperatures of produced fluids around the inflow mixing
point provides a significant amount of data necessary to determine
inflowing produced fluid rates so far as there exists a measureable
difference between the temperatures of the inflow and upstream
fluids. Along with topside metered production rates and
compositional data, the total production can be accurately
allocated back to each production section of the wellbore by use of
the matrix temperature production logging tool described
herein.
[0015] Referring now to FIG. 1, a sectional view depicts the matrix
temperature production log tool 10 disposed within a wellbore 1.
The wellbore may be a borehole, a casing or a tubing string. For
explanatory purposes, the tool 10 described as being disposed
within a tubing string 20. It should be understood, however, that
the principles described herein can be applied to many different
wellbore structures, i.e., cased or uncased, horizontal or
vertical. The tubing string may be horizontal or vertical. The
tubing string 20 includes an inner surface 21. The tubing string
may also include perforations and/or slots.
[0016] Referring to FIG. 1, the tool 10 includes a core structure
30, a plurality of arms 40 extendibly and pivotally mounted to the
core structure 30 and a plurality of temperature sensors 50
attached to each arm 40. The tool may be centralized within the
tubing string through the use of a limited number of additional
pivoted arms deployed both upstream and downstream or just upstream
or downstream of the temperature sensors.
[0017] The tool 10 also includes a computer assembly or data
transfer device, not shown. The computer assembly is typically
disposed within the core structure 30 for receiving, processing,
and storing and/or transmitting electronic signals generated from
the tool 10. For instance, the computer assembly receives
electronic signals from the temperature sensors attached to each
individual pivoted arm and then stores and/or transmits the data.
The computer assembly may also include an electronic clock
arrangement, batteries, and other circuits for storage and/or
transmitting of data. The tool can further be coupled to a fiber
optic line, not depicted, which may be deployed inside the
wellbore. Data related to the wellbore gathered by the tool may be
transmitted in real-time to the surface through the fiber optic
line. The data can also be transmitted real-time via the data
transfer device.
[0018] The core structure is kept away from the tubing string to
ensure flow around the entire circumference of the core structure.
Additionally, by keeping the core structure from contacting the
inner surface of the tubing string, the temperature sensors at the
tips or ends of the arms are given an opportunity to measure flow
from perforations present at those locations where that contact
between the tool's core structure and the tubing string would
occur.
[0019] Individual arms or pivoted arms or pivoted rods or slender
plates are extendibly pivotally attached to the core structure by a
connection member, not shown, such as a pin. The arms do not rotate
around the core structure. Rather, each of the arms will only pivot
in their one plane relative to the core structure. Rotation of the
arms about the core structure may cause unwanted mixing of the
inflow and upstream fluids rendering the temperature measurement at
the location of inflow less accurate. Although the tool 10 in FIG.
1 shows sixteen (16) arms, the number of arms attached to the core
structure depends on operator need and mechanical feasibility. Any
number of arms may radially extend from the core structure, i.e.,
deploy. Any number of arms may also be in an un-deployed position,
wherein the arms are not radially extended from the core structure.
The number of pivoted arms deployed and/or un-deployed depends on
operator need and mechanical feasibility. The pivoted arms may be
arranged and configured around the core structure to obtain data
from substantially the entire circumferential interior surface of
the tubing string. At least one arm must be deployed in order for
the temperature sensors to account for the temperature of produced
fluid flowing into the tubing string. Preferably, the tool includes
a plurality of deployed arms. The plurality of pivoted arms should
be evenly spaced around the circumference of a core structure. When
all the pivoted arms are deployed, the probability that a
temperature sensor passes through the fluid flowing into the well
from the reservoir increases. The arms may be manually or
automatically extended or retracted. Each arm independently
responds to the geometric anomalies or other changes in the
configuration of the inner surface of the tubing string, such as
dents, protrusions or bulges.
[0020] The arms serve as both the mounting and positioning
structure for the temperature sensors. FIG. 1 depicts two
temperature sensors 50 per arm 40. At least one temperature sensor
per arm should be located at the end or tip of the pivoted arm so
as to be at or near the inner surface of the tubing string when the
arm is deployed. Additional temperature sensors may be mounted on
the arm. The additional temperature sensors may be mounted between
the core structure and the tip of the pivoted arm where the initial
temperature sensor is located. It is preferably to have a plurality
of temperature sensors located along each arm.
[0021] The temperature sensors record the temperature of produced
fluid flowing into and within the tubing string. Temperature
sensors can include, but are not limited to, resistive temperature
sensing devices, thermocouples, thermistors, infrared, pressure of
known encased fluid, and laser or laser light within fiber optics.
Other types of sensors can also be incorporated into the arms, such
as sensors to determine the fluid phase(s) would provide further
information that would enhance the allocation of production
data.
[0022] FIG. 2 depicts a plot of simulated production fluid through
a 10,000 foot horizontal tubing string with a total production rate
of 500 barrels of oil per day. There were nine (9) inflow locations
where equal amounts of produced fluid were flowing into the
wellbore. The temperature data from the simulation was used to
confirm that if three temperatures (inflow, upstream, downstream)
at each inflow location could be measured, then production could be
allocated to each location.
[0023] In closing, it should be noted that the discussion of any
reference is not an admission that it is prior art to the present
invention, especially any reference that may have a publication
date after the priority date of this application. At the same time,
each and every claim below is hereby incorporated into this
detailed description or specification as an additional embodiment
of the present invention.
[0024] Although the systems and processes described herein have
been described in detail, it should be understood that various
changes, substitutions, and alterations can be made without
departing from the spirit and scope of the invention as defined by
the following claims. Those skilled in the art may be able to study
the preferred embodiments and identify other ways to practice the
invention that are not exactly as described herein. It is the
intent of the inventors that variations and equivalents of the
invention are within the scope of the claims while the description,
abstract and drawings are not to be used to limit the scope of the
invention. The invention is specifically intended to be as broad as
the claims below and their equivalents.
* * * * *