U.S. patent application number 14/263271 was filed with the patent office on 2014-12-04 for method of hydraulic fracture identification using temperature.
This patent application is currently assigned to CONOCOPHILLIPS COMPANY. The applicant listed for this patent is CONOCOPHILLIPS COMPANY. Invention is credited to Rick H. DEAN, Kyle FRIEHAUF.
Application Number | 20140358444 14/263271 |
Document ID | / |
Family ID | 51986065 |
Filed Date | 2014-12-04 |
United States Patent
Application |
20140358444 |
Kind Code |
A1 |
FRIEHAUF; Kyle ; et
al. |
December 4, 2014 |
METHOD OF HYDRAULIC FRACTURE IDENTIFICATION USING TEMPERATURE
Abstract
A method for identifying fractures in a formation.
Inventors: |
FRIEHAUF; Kyle; (Katy,
TX) ; DEAN; Rick H.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
CONOCOPHILLIPS COMPANY |
Houston |
TX |
US |
|
|
Assignee: |
CONOCOPHILLIPS COMPANY
Houston
TX
|
Family ID: |
51986065 |
Appl. No.: |
14/263271 |
Filed: |
April 28, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61829374 |
May 31, 2013 |
|
|
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Current U.S.
Class: |
702/11 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 47/07 20200501; E21B 47/135 20200501 |
Class at
Publication: |
702/11 |
International
Class: |
E21B 47/06 20060101
E21B047/06 |
Claims
1. A method for identifying fractures in a formation having a
wellbore comprising: a. positioning a sensor within the wellbore,
wherein the sensor generates a feedback signal representing at
least one of a temperature and pressure measured by the sensor; b.
injecting a fluid into the wellbore and into at least a portion of
the formation adjacent the sensor; c. waiting a predetermined
period of time; d. generating a standstill simulated model
representing at least one simulated temperature characteristic and
at least one pressure characteristic of the formation during and
after fluid injection; e. shutting-in the wellbore for a
pre-determined shut-in period; f. generating a shut-in simulated
model representing at least one simulated temperature
characteristic and at least one pressure characteristic of the
formation during the shut-in period; g. generating a data model
representing the standstill simulated model and the shut-in
simulated model, wherein the data model is derived from the
feedback signal; and h. observing the data model for presence of
fractures within the wellbore, wherein fractures are present when
the temperature characteristics are lower than the temperature
characteristics of other sections of the wellbore.
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. 61/829,374 filed 31 May, 2013, entitled
"METHOD OF HYDRAULIC FRACTURE IDENTIFICATION USING TEMPERATURE,"
which is incorporated herein in its entirety.
FIELD OF THE INVENTION
[0002] This invention relates to a method for identifying the
presence of fracture in a wellbore during and after treatment.
BACKGROUND OF THE INVENTION
[0003] Hydraulic fracturing, matrix acidizing, and other types of
stimulation treatments are routinely conducted in oil and gas wells
to enhance hydrocarbon production. The wells being stimulated often
include a large section of perforated casing or an open borehole
having significant variation in rock petrophysical and mechanical
properties. As a result, a treatment fluid pumped into the well may
not flow to all desired hydrocarbon bearing layers that need
stimulation. To achieve effective stimulation, the treatments often
involve the use of diverting agents in the treating fluid, such as
chemical or particulate material, to help reduce the flow into the
more permeable layers that no longer need stimulation and increase
the flow into the lower permeability layers.
[0004] However, during a stimulation treatment, the flow
distribution in a well can change quickly due to either stimulation
of the formation layers to increase their flow capacity or
temporary reduction in flow capacity as a result of diverting
agents. To determine the effectiveness of stimulation or diversion
in the well, an instantaneous measurement that gives a "snap shot"
of the flow distribution in a well is desired. Unfortunately, there
are few such techniques available.
[0005] One technique for substantially instantaneous measurement is
fiber optic Distributed Temperature Sensing (DTS) technology. DTS
typical includes an optical fiber disposed in the wellbore (e.g.
via a permanent fiber optic line cemented in the casing, a fiber
optic line deployed using a coiled tubing, or a slickline unit).
The optical fiber measures a temperature distribution along a
length thereof based on an optical time-domain (e.g. optical
time-domain reflectometry (OTDR), which is used extensively in the
telecommunication industry).
[0006] One advantage of DTS technology is the ability to acquire in
a short time interval the temperature distribution along the well
without having to move the sensor as in traditional well logging
which can be time consuming. DTS technology effectively provides a
"snap shot" of the temperature profile in the well. DTS technology
has been utilized to measure temperature changes in a wellbore
after a stimulation injection, from which a flow distribution of an
injected fluid can be qualitatively estimated. The inference of
flow distribution is typically based on magnitude of temperature
"warm-back" during a shut-in period after injecting a fluid into
the wellbore and surrounding portions of the formation. The
injected fluid is typically colder than the formation temperature
and a formation layer that receives a greater fluid flow rate
during the injection has a longer "warm back" time compared to a
layer or zone of the formation that receives relatively less flow
of the fluid.
[0007] As a non-limiting example, FIG. 1 illustrates a graphical
plot 2 of a plurality of simulated temperature profiles 4 of a
laminated formation 6 during a six hour time period of "warm back",
according to the prior art. As shown, the X-axis 8 of the graphical
plot 2 represents temperature in Kelvin (K) and the Y-axis 9 of the
graphical plot 2 represents a depth in meters (m) measured from a
pre-determined surface level. As shown, a permeability of each
layer of the laminated formation 6 is estimated in units of
millidarcies (mD). The layers of the formation 6 having a
relatively high permeability receive more fluid during injection
and a time period for "warm back" is relatively long (i.e. after a
given time period, a change in temperature is less than a change in
temperature of the layers having a lower permeability). The layers
of the formation 6 having a relatively low permeability receive
less fluid during injection and a time period for "warm back" is
relatively short (i.e. after a given time period, a change in
temperature is greater than a change in temperature of the layers
having a higher permeability).
[0008] By obtaining and analyzing multiple DTS temperature traces
during the shut-in period, the injection rate distribution among
different formation layers can be determined. However, current DTS
interpretation techniques and methods are based on visualization of
the temperature change in the DTS data log, and is qualitative in
nature, at best. The current interpretation methods are further
complicated in applications where a reactive fluid, such as acid,
is pumped into the wellbore, wherein the reactive fluid reacts with
the formation rock and can affect a temperature of the formation,
leading to erroneous interpretation. In order to achieve effective
stimulation, more accurate DTS interpretation methods are needed to
help engineers determine the flow distribution in the well and make
adjustments in the treatment accordingly.
SUMMARY OF THE INVENTION
[0009] In an embodiment, a method for identifying fractures in a
formation having a wellbore includes: (a) positioning a sensor
within the wellbore, wherein the sensor generates a feedback signal
representing at least one of a temperature and pressure measured by
the sensor; (b) injecting a fluid into the wellbore and into at
least a portion of the formation adjacent the sensor; (c) waiting a
predetermined period of time; (d) generating a standstill simulated
model representing at least one simulated temperature
characteristic and at least one pressure characteristic of the
formation during and after fluid injection; (e) shutting-in the
wellbore for a pre-determined shut-in period; (f) generating a
shut-in simulated model representing at least one simulated
temperature characteristic and at least one pressure characteristic
of the formation during the shut-in period; (g) generating a data
model representing the standstill simulated model and the shut-in
simulated model, wherein the data model is derived from the
feedback signal; and (h) observing the data model for presence of
fractures within the wellbore, wherein fractures are present when
the temperature characteristics are lower than the temperature
characteristics of other sections 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 graphical plot of a plurality of simulated
temperature profiles during a six house period of warm back,
according to the prior art.
[0012] FIG. 2 is a schematic diagram of an embodiment of the
present invention.
[0013] FIG. 3 is a graphical plot showing an embodiment of a
temperature profile for a wellbore in accordance with the present
invention.
DETAILED DESCRIPTION OF THE INVENTION
[0014] 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.
[0015] Referring now to FIG. 2, there is shown an embodiment of a
wellbore treatment system according to the invention, indicated
generally at 10. As shown, the system 10 includes a fluid
injector(s) 12, a sensor 14, and a processor 16. It is understood
that the system 10 may include additional components.
[0016] The sensor 14 is typically of Distributed Temperature
Sensing (DTS) technology including an optical fiber 18 disposed in
the wellbore (e.g. via a permanent fiber optic line cemented in the
casing, a fiber optic line deployed using a coiled tubing, or a
slickline unit). The optical fiber 18 measures the temperature
distribution along a length thereof based on optical time-domain
(e.g. optical time-domain reflectometry). In certain embodiments,
the sensor 14 includes a pressure measurement device 19 for
measuring a pressure distribution in the wellbore and surrounding
formation. In certain embodiments, the sensor 14 is similar to the
DTS technology disclosed in U.S. Pat. No. 7,055,604 B2, hereby
incorporated herein by reference in its entirety.
[0017] The processor 16 is in data communication with the sensor 14
to receive data signals (e.g. a feedback signal) therefrom and
analyze the signals based upon a pre-determined algorithm,
mathematical process, or equation, for example. As shown in FIG. 2,
the processor 16 analyzes and evaluates a received data based upon
an instruction set 20. The instruction set 20, which may be
embodied within any computer readable medium, includes processor
executable instructions for configuring the processor 16 to perform
a variety of tasks and calculations. As a non-limiting example, the
instruction set 20 may include a comprehensive suite of equations
governing a physical phenomenon of fluid flow in the formation, a
fluid flow in the wellbore, a fluid/formation (e.g. rock)
interaction in the case of a reactive stimulation fluid, a fluid
flow in a fracture and its deformation in the case of hydraulic
fracturing, and a heat transfer in the wellbore and in the
formation. As a further non-limiting example, the instruction set
20 includes a comprehensive numerical model for carbonate acidizing
such as described in Society of Petroleum Engineers (SPE) Paper
107854, titled "An Experimentally Validated Wormhole Model for
Self-Diverting and Conventional Acids in Carbonate Rocks Under
Radial Flow Conditions," and authored by P. Tardy, B. Lecerf and Y.
Christanti, hereby incorporated herein by reference in its
entirety. It is understood that any equations can be used to model
a fluid flow and a heat transfer in the wellbore and adjacent
formation, as appreciated by one skilled in the art of wellbore
treatment. It is further understood that the processor 16 may
execute a variety of functions such as controlling various settings
of the sensor 14 and the fluid injector 12, for example.
[0018] A temperature of the injected fluid is typically lower than
a temperature of each of the layers of the formation. Throughout
the injection period, the colder fluid removes thermal energy from
the wellbore and surrounding areas of the formation. Typically, the
higher the inflow rate into the formation, the greater the injected
fluid volume (i.e. its penetration depth into the formation), and
the greater the cooled region. In the case of hydraulic fracturing,
the injected fluid enters the created hydraulic fracture and cools
the region adjacent to the fracture surface. When pumping stops,
the heat conduction from the reservoir gradually warms the fluid in
the wellbore. Where a portion of the formation does not receive
inflow during injection will warm back faster due to a smaller
cooled region, while the formation that received greater inflow
warms back more slowly.
[0019] After injection of fluid into the well, wait a predetermined
period of time before shitting in the well. While waiting, any
number of operations may be performed except injecting fluid that
is comparable to the total heat transfer of hydraulic fracturing
into the well. Some operations, for example, include to plug or
ball-seat drill outs, clean-outs, produced, cased hole logging
runs, etc.
[0020] FIG. 3 illustrates a graphical plot 48 of the temperature
profiles normal to fracture at various time periods. The region
near the well warms up quickly just after the injection period
ends, but the temperature at the well is still about 15.degree. F.
less than the initial reservoir temperature.
[0021] 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 a additional embodiments
of the present invention.
[0022] 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.
* * * * *