U.S. patent application number 12/135453 was filed with the patent office on 2008-12-18 for real time closed loop interpretation of tubing treatment systems and methods.
Invention is credited to Rex Burgos, Moussa Kane, Hubertus V. Thomeer, Xiaowei Weng.
Application Number | 20080308272 12/135453 |
Document ID | / |
Family ID | 40130271 |
Filed Date | 2008-12-18 |
United States Patent
Application |
20080308272 |
Kind Code |
A1 |
Thomeer; Hubertus V. ; et
al. |
December 18, 2008 |
Real Time Closed Loop Interpretation of Tubing Treatment Systems
and Methods
Abstract
A technique facilitates the treatment of a subterranean
formation. The technique involves the use of a fluid delivery
system that comprises a continuous feedback system. The continuous
feedback system utilizes a real time closed loop interpretation
technique to instantaneously synchronize and adjust actions at a
well site surface relative to measured downhole events. Sensors are
used to monitor at least one downhole property in real time. Based
on the real time data, the continuous feedback system enables
adjustments to be made with respect to the at least one property in
a manner designed to influence a downhole event.
Inventors: |
Thomeer; Hubertus V.;
(Houston, TX) ; Burgos; Rex; (Richmond, TX)
; Weng; Xiaowei; (Katy, TX) ; Kane; Moussa;
(Houston, TX) |
Correspondence
Address: |
SCHLUMBERGER TECHNOLOGY CORPORATION;David Cate
IP DEPT., WELL STIMULATION, 110 SCHLUMBERGER DRIVE, MD1
SUGAR LAND
TX
77478
US
|
Family ID: |
40130271 |
Appl. No.: |
12/135453 |
Filed: |
June 9, 2008 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60934258 |
Jun 12, 2007 |
|
|
|
Current U.S.
Class: |
166/250.15 ;
166/53 |
Current CPC
Class: |
E21B 43/00 20130101;
E21B 44/00 20130101; E21B 43/25 20130101; E21B 47/00 20130101 |
Class at
Publication: |
166/250.15 ;
166/53 |
International
Class: |
E21B 43/12 20060101
E21B043/12 |
Claims
1. A method of treating a subterranean formation, comprising:
providing a fluid delivery apparatus, wherein the fluid delivery
apparatus comprises a continuous feedback system including a real
time closed loop interpretation technique to instantaneously
synchronize and adjust actions at a well site surface relative to
measured downhole items of interest; introducing the fluid delivery
apparatus into a wellbore penetrating a subterranean formation;
monitoring and evaluating, in real time, at least one downhole
property or measurement to detect in real time at least one
downhole item of interest; and upon detection of the at least one
downhole item, adjusting in real time at least one parameter to
influence and/or control the downhole item.
2. The method as recited in claim 1, wherein providing comprises
forming the fluid delivery apparatus with coiled tubing.
3. The method as recited in claim 1, wherein providing further
comprises forming the fluid delivery apparatus with a data
acquisition, analysis, and control system.
4. The method as recited in claim 1, wherein detecting the at least
one downhole item comprises detecting one of stuck potential,
diversion, stimulation, over/under balance, nozzle efficiency,
downhole tool load, real time extended reach, pressure
differential, pressure spike, changes in measurement over time
slope, injectivity profile, fluid placement, and volume
characterization of deposited scale.
5. The method as recited in claim 1, wherein monitoring and
evaluating comprises monitoring and evaluating at least one of
pressure, load, fluid velocity, fluid direction, temperature, fluid
pH, fluid solids content, and fluid density.
6. The method as recited in claim 1, further comprising measuring
the at least one downhole property or measurement using at least
one of an acoustic sensor, an infrared sensor, an optical sensor,
and a flow sensor.
7. A system for treating a subterranean formation, comprising: a
tubing string to deliver a fluid through a wellbore to a
subterranean formation; a sensor positioned downhole to measure a
downhole property able to provide an indication of a downhole event
or environment; and a continuous feedback system coupled to the
sensor, wherein the continuous feedback system utilizes a real
time, closed loop interpretation technique to instantaneously
synchronize and adjust actions at a surface location to offset the
downhole event or environment.
8. The system as recited in claim 7, wherein the continuous
feedback system comprises a control system used for adjustment of
at least one parameter in real time to offset the downhole event or
environment.
9. The system as recited in claim 8, wherein the control system
comprises a processor based control system at a surface
location.
10. The system as recited in claim 9, wherein the control system is
located proximate the wellbore.
11. The system as recited in claim 9, wherein the control system is
located remote from the wellbore.
12. The system as recited in claim 7, wherein the tubing string
comprises coiled tubing.
13. The system as recited in claim 7, wherein the sensor comprises
a plurality of sensors.
14. The system as recited in claim 13, wherein the plurality of
sensors are used to monitor a plurality of downhole properties.
15. A method of treating a subterranean formation, comprising:
performing a fluid treatment operation downhole; monitoring in real
time at least one downhole property related to the fluid treatment
operation; using a real time closed loop interpretation technique
on a continuous feedback system to evaluate data obtained from
monitoring in real time the at least one downhole property; and
adjusting the at least one downhole property based on the
evaluation of data to provide a desired influence downhole.
16. The method as recited in claim 15, wherein performing comprises
delivering a treatment fluid downhole through a coiled tubing.
17. The method as recited in claim 15, wherein monitoring comprises
monitoring pressure at a desired downhole location.
18. The method as recited in claim 15, wherein monitoring comprises
monitoring temperature at a desired downhole location.
19. The method as recited in claim 15, wherein monitoring comprises
monitoring a treatment fluid characteristic at a desired downhole
location.
20. The method as recited in claim 15, wherein adjusting comprises
using a data acquisition, analysis and control system to adjust the
at least one downhole property.
21. A system, comprising: a well treatment system having a fluid
delivery apparatus, the fluid delivery apparatus comprising a
continuous feedback system having a real time closed loop
interpretation technique to instantaneously synchronize and adjust
actions relative to measured downhole items of interest.
22. The system as recited in claim 21, wherein the well treatment
system further comprises a data acquisition, analysis and control
system to monitor and evaluate in real time at least one downhole
property used as an indicator of a downhole event or
environment.
23. The system as recited in claim 22, wherein the well treatment
system comprises a plurality of sensors located downhole to monitor
the at least one downhole property.
24. The system as recited in claim 23, wherein the fluid delivery
apparatus comprises coiled tubing.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims priority under 35 U.S.C. .sctn.
119(e) to U.S. Provisional Application Ser. No. 60/934,258, filed
on Jun. 12, 2007, which is incorporated herein by reference.
BACKGROUND
[0002] A variety of systems and methods are used for making
downhole measurements related to well treatment operations.
Downhole measurements are made and the data is conveyed upwardly
via fluid pulse signals, electromagnetic wireless signals, or
hardwired electric signals. The measurements can be used to
determine an event or downhole property/measurement, but existing
systems and methods are limited in their ability to provide an
operator with a comprehensive understanding of the downhole
event/environment. Additionally, the measurements generally are
typically performed for a single event.
[0003] Furthermore, existing systems and methods fail to enable
sufficient control of downhole conditions and/or events. Surface
measurements must be correlated with downhole measurements before
an action can be taken. No continuous feedback loop is provided to
enable real time decisions, and substantial dependence on operator
input is required to achieve a desired output and/or event
downhole. The existing systems are not well-suited for use at the
surface in a manner that enables synchronization and rapid
adjustment in response to events happening in the well. These
limitations reduce downhole efficiency and/or reservoir
optimization.
SUMMARY
[0004] In general, the present invention provides a system and
method for treating a subterranean formation. The system and method
utilize a fluid delivery apparatus that comprises a continuous
feedback system utilizing a real time closed loop interpretation
technique to instantaneously synchronize and adjust actions at a
well site surface relative to measured downhole events. Sensors are
used to monitor at least one downhole property/measurement, in real
time. Based on the real time data from surface and downhole,
adjustments can be made to manage and to influence a downhole event
or environment.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] Certain embodiments of the invention will hereafter be
described with reference to the accompanying drawings, wherein like
reference numerals denote like elements, and:
[0006] FIG. 1 is a schematic front elevation view of a well
treatment system positioned to deploy a fluid to a well formation,
according to an embodiment of the present invention;
[0007] FIG. 2 is a graphical representation of real time data
output from a subterranean location in a form that can be displayed
via a graphical user interface, according to an embodiment of the
present invention;
[0008] FIG. 3 is a schematic front elevation view of another
example of a well treatment system positioned to obtain data in
multiple well zones, according to an embodiment of the present
invention;
[0009] FIG. 4 is another example of a displayed output based on
data obtained from a downhole location, according to an embodiment
of the present invention;
[0010] FIG. 5 is another example of a graphical user interface for
providing information and enabling operator input, according to an
embodiment of the present invention;
[0011] FIG. 6 is another example of a graphical user interface for
providing information and enabling operator input, according to an
embodiment of the present invention;
[0012] FIG. 7 is another example of a graphical user interface for
providing information based on downhole data, according to an
embodiment of the present invention;
[0013] FIG. 8 is another example of a graphical user interface for
providing information and enabling operator input, according to an
embodiment of the present invention;
[0014] FIG. 9 is a graph illustrating pressure versus true vertical
depth during a run-in-hole, according to an alternate embodiment of
the present invention;
[0015] FIG. 10 is an illustration similar to that of FIG. 9;
[0016] FIG. 11 is a schematic front elevation view of a well
treatment system being run-in-hole and the resultant change in
fluid level, according to an embodiment of the present
invention;
[0017] FIG. 12 is a graph illustrating true vertical depth,
pressure and gradient versus time, according to an embodiment of
the present invention;
[0018] FIG. 13 is another example of a graphical user interface for
providing information and enabling operator input, according to an
embodiment of the present invention;
[0019] FIG. 14 illustrates a matrix that can be utilized to
determine the level of risk associated with a given well treatment
operation, according to an embodiment of the present invention;
[0020] FIG. 15 illustrates another matrix that can be utilized to
determine the level of risk associated with a given well treatment
operation, according to an embodiment of the present invention;
[0021] FIG. 16 illustrates another matrix that can be utilized to
determine the level of risk associated with a given well treatment
operation, according to an embodiment of the present invention;
[0022] FIG. 17 illustrates another matrix that can be utilized to
determine the level of risk associated with a given well treatment
operation, according to an embodiment of the present invention;
and
[0023] FIG. 18 is another example of a graphical user interface for
providing information and enabling operator input, according to an
embodiment of the present invention.
DETAILED DESCRIPTION
[0024] In the following description, numerous details are set forth
to provide an understanding of the present invention. However, it
will be understood by those of ordinary skill in the art that the
present invention may be practiced without these details and that
numerous variations or modifications from the described embodiments
may be possible.
[0025] The present invention generally relates to a system and
method for closed loop interpretation during fluid treatment of a
subterranean reservoir using a fluid delivery apparatus including a
tubing string that may be formed of coiled tubing. In one
embodiment, the system and method relate to a real time closed loop
interpretation method for coiled tubing services to synchronize and
adjust actions at the surface with events happening downhole to
improve downhole efficiency and/or reservoir optimization. The
improvements in downhole efficiency and reservoir optimization can
result from improved pressure management, load management, downhole
tool management, reservoir management, and/or management of other
aspects of the fluid treatment operation. The system and
methodology provide solutions to a need for control over the
operation by enabling synchronization and adjustment of actions at
the surface relative to prior, current, or future downhole events
through real time closed loop interpretation of subterranean
treatments.
[0026] The real time control technique can be used in relationship
to one or more downhole events. For example, detection and
adjustment in real time of downhole events related to pressure
management may include making adjustments related to stuck
potential, diversion indicators, stimulation indicators, staying on
target (over and under a set downhole pressure), and treatment
fluid nozzle efficiency. Adjustment of the downhole event also may
relate to load management and include downhole events related to
weight on downhole tools and real time extended reach control.
Detection and control also can be related to downhole tool
management and include control of downhole devices that are
sensitive to pressure differentials, spikes, changes in slope
(increasing, flat or decreasing), and compressive, tensile or
torsional forces. The detection and control also can be related to
reservoir management and include downhole events characterized as
injectivity profiles, placement of treatment fluids, location and
volume characterization of deposited scale in the tubulars and
reservoir, testing reservoir properties (e.g. capacity,
deliverability), and characterization, predicting and identifying
injection profiles.
[0027] As described in greater detail below, novel systems and
methodology utilize real time closed loop interpretation for
subterranean treatment services that provide distinct advantages
and benefits. The advantages and benefits arise come at least in
part, from the ability to predict the dynamic behaviors and/or
events both at the surface and downhole, to provide feedback
related to the downhole events or control of those events, and to
control or adjust the downhole events. Furthermore, the control
system enables monitoring of one or more properties that can be
used in exercising control over multiple downhole events. The
detection and control of the specific downhole events are enabled
based on monitoring and evaluation of properties, such as pressure,
load, velocity, and other indicative properties, with data
available both downhole and at a surface location.
[0028] According to one embodiment of the invention, real time
closed loop interpretation is used with coiled tubing systems and
methods to predict a desired output for a desired a downhole event.
Downhole properties are measured, and the measurements are sent to
the surface as feedback. The feedback is used by a control system
that can change the properties downhole and affect the downhole
event. Values can be input into the control system to affect
control over the downhole event as desired by a well operator.
[0029] In other embodiments, downhole properties may be measured,
and the measurement data can be evaluated with a suitable control
device located within the wellbore. The control device can be used
to monitor feedback and to influence or control the downhole event
based on the feedback information. Additionally, the monitoring and
evaluation can be accomplished by a combined surface control system
and downhole control system. Furthermore, the techniques for
monitoring downhole properties and controlling downhole events in
treatment operations are amenable for use with coiled tubing
services and systems, but they also can be used with other suitable
formation treatment techniques and equipment.
[0030] The system and methodology is useful for real time closed
loop interpretation of coiled tubing services that involve
characterizing an event, determining the trajectory, estimating the
likelihood and potential severity of an occurrence of a specific
downhole event, and displaying the information to an operator. The
technique also can be used to optimize a service plan by first
selecting an initial plan, determining the likelihood and severity
of a downhole event, adjusting a parameter of the initial plan,
reevaluating the likelihood and severity of the downhole event, and
then repeating the process of adjusting and reevaluating as
desired. The technique also can be used to provide a real time
closed loop interpretation of coiled tubing services involving
predicting in real time the tendency toward an event by acquiring
both surface and downhole data. The data is used to determine and
predict the ensuing operations and treatment outcome tendencies
with closed loop calculations.
[0031] Similarly, the system and methodology can be used to provide
a real time closed loop interpretation of coiled tubing services
involving a system for warning of coiled tubing/pipe sticking by
monitoring downhole and surface data. Ongoing data can be obtained
and compared for differences. If sufficient differences arise, an
alarm can be raised to indicate the onset of a downhole event due
to changing parameters. The alarm enables intervention by an
operator or automatic intervention by a control system able to take
remedial action.
[0032] The technique also can be used to provide real time closed
loop interpretation of coiled tubing services involving a method
for determining one or more properties of a well treatment related
event or plan by estimating the properties at one position in the
wellbore and then at a second position. After estimating the
properties, the well is flowed, and the measurements are repeated
at the first and second positions. This process can be repeated as
necessary to enable the verification of baselines and to make the
necessary changes as baselines change. In some embodiments, the
data from repeated measurements at the first and second positions
is transmitted to the surface and recorded for determination of
flow properties.
[0033] Referring generally to FIG. 1, one embodiment of a well
treatment system 20 is illustrated as deployed for use in a real
time closed loop interpretation of tubing services, e.g. coiled
tubing services. The system provides the ability to predict the
dynamic behaviors/events both at the surface and downhole and to
exercise control over downhole events based on feedback. The
feedback can be gained by measuring and evaluating downhole
properties, such as pressure, load, velocity, and other suitable
properties. These properties can be measured both downhole and at
the surface.
[0034] As illustrated in FIG. 1, well treatment system 20 may
comprise or be in the form of a fluid delivery system or apparatus
comprising a continuous feedback system 22 that utilizes a real
time closed loop interpretation technique to instantaneously
synchronize and adjust actions at the surface relative to measured
downhole events. The continuous feedback system 22 comprises a well
treatment tubing string 24 deployed in a wellbore 26, a sensor
system 28, and a control system 30 that may comprise a data
acquisition, analysis and control system.
[0035] Well treatment tubing string 24 comprises a treatment tool
32 deployed downhole to a desired location in wellbore 26 proximate
a surrounding subterranean formation 34 that is to be treated.
Treatment tool 32 is conveyed through wellbore 26 via a tubing 36,
such as coiled tubing, that is conveyed downhole from suitable
surface equipment 38 positioned at a surface location 40. Surface
equipment 38 may comprise a coiled tubing rig designed to
selectively deliver coiled tubing downhole and withdraw the coiled
tubing and treatment tool 32.
[0036] During a well treatment operation, a treatment fluid is
pumped downhole by suitable pumping equipment 42 that also may be
positioned at surface location 40. Control system 30 also may be
coupled to pumping equipment 42 to control delivery of treatment
fluid based on monitored properties, and thereby influence/control
downhole events. The treatment fluid is flowed down through tubing
36 and out through treatment tool 32, as represented by arrows 44.
From treatment tool 32, the treatment fluid is forced outwardly
into formation 34 through, for example, perforations 46 formed in a
well casing 48. The treatment fluid and the configuration of
treatment tool 32 can vary depending on the specific treatment
operation and the environment in which the operation is
conducted.
[0037] Sensor system 28 can be used to detect, in real time, at
least one downhole property or measurement that can be used as an
indicator for at least one downhole item, e.g. an event or an
environment. For example, sensor system 28 may have a plurality of
sensors 50 comprising, for example, one or more pressure sensors,
temperature sensors, load sensors, casing collar locator sensors,
fluid characteristic sensors, e.g. fluid velocity sensors, acoustic
sensors, infrared sensors, optical sensors, flow sensors, and other
types of sensors designed to detect and monitor one or more
properties that can be used as an indicator of a downhole event.
Depending on the property measured and the downhole
event/environment, changes in the property/measurement can be an
indication of the future occurrence, the current occurrence or the
past occurrence of a downhole item of interest, such as an event or
an environment. Sensors 50 also can be positioned at other
locations, such as surface locations to provide, for example,
comparison data that can be used for comparing, calibrating, or
verifying downhole data.
[0038] Data from sensor system 28 is output in real time to data
acquisition, analysis, and control system 30. Control system 30 may
have a variety of forms and may be located in whole or in part at
the well site/surface location 40 or at remote locations.
Additionally, control system 30 may be a processor based control
system, such as a computer control system in which data from sensor
system 28 is processed on one or more computers. Control system 30
also can be automated to automatically provide predetermined
control signals based on the real time detection of the at least
one downhole property/measurement. For example, changes in the
downhole property/measurement may cause control system 30 to take
an automated control action to change the downhole
property/measurement and to thereby influence and/or control a
downhole event or environment.
[0039] In the example illustrated, sensor system 28 communicates
with control system 30 via one or more control lines 52. The
control line 52 may comprise a wired control line, a wireless
control line, or combinations of wired and wireless segments for
conveying signals from sensors 50 to control system 30 in real
time. By way of example, the control system 30 may comprise a
plurality of input/output units 54, and at least one or more of the
units 54 may comprise computers 56 for processing and analyzing
data received from sensor system 28 in real time. A variety of
software programs can be loaded on the computer or computers 56
depending on the downhole property/measurement being monitored.
Additionally, a plurality of the computers 56 can be used in
cooperation by processing certain data on one computer and other
data on another computer.
[0040] As illustrated, each unit 54 may comprise a display 58, to
display information to an operator, and an input device 60, such as
a keypad or touchscreen, to enable the operator to input
information. In many applications, one or more of the displays 58
can be used to provide a graphical user interface 62 for displaying
information and for prompting the operator to input detection,
analysis, and control related information. Depending on the
structure of control system 30, a variety of other components can
be used to convey and evaluate data. For example, a router or other
suitable equipment 64 can be used to disseminate information to a
plurality of units 54. Additionally, a variety of transmitters and
receivers 66 can be used to receive and transmit from, for example,
a remotely located computer.
[0041] The continuous feedback system 22 can be used in a variety
of applications for sensing many types of properties that
facilitate the control of many types of potential downhole events.
By way of example, the measured downhole property/measurement may
comprise pressure, load, fluid velocity, fluid direction,
temperature, fluid pH, fluid solids content, fluid density, and
other properties. Individual properties or combinations of
properties can be detected and used as an indicator of specific
downhole events and/or environments. Examples of such downhole
events include stuck potential, diversion, stimulation, over/under
balance, nozzle efficiency, downhole tool load, real time extended
reach, pressure differential, pressure spikes, changes in
measurement over time slope (increasing, flat or decreasing),
injectivity profile, fluid placement, volume characterization of
deposited scale, and a variety of reservoir properties. The
description below provides a variety of examples with respect to
uses of continuous feedback system 22, however the system can be
used in other applications and environments.
[0042] For example, in some embodiments of the invention, pressure
management can be achieved by obtaining data from one or more of
the downhole sensors 50. The control system 30 serves as an
acquisition and analysis system and also displays various
information and indicators to an operator via one or more displays
58. For example, the control system can be used to provide a real
time indicator based on changes in a downhole pressure measurement
and/or changes in other measurements, such as temperature or casing
collar locator measurements.
[0043] Information can be displayed via displays 58 in a variety of
formats, including a horizontal time log 68, as illustrated in FIG.
2. In this example, control system 30 creates a time based
horizontal log and can perform a variety of operations on the time
log, including annotations, printing, scale changes, add/delete
tracks, or multiple time log windows. Additionally, specific
channels can be selected for display on horizontal time log 68 from
a predetermined list of channels available or downloaded on the
control system 30. In addition to existing downhole
sensors/measurements channels, the list also can include calculated
channels, such as foam quality, calculated bottom hole pressure,
and derivative temperature. In FIG. 2, for example, graph lines 70
illustrate display channels representative of foam quality
measurements or of a variety of other downhole property
measurements. Additionally, the time based log can be used to
display selected threshold values, as referenced by graph lines 72.
The selected threshold values can be entered by an operator via
graphical user interface 62 or via another suitable input
device.
[0044] By way of example, when the measured downhole property is
foam quality suitable threshold values are selected, e.g. foam
quality limits at 60% to 70%, and those values are displayed via
graph lines 72. The foam quality is determined by control system 30
based on pressure and temperature measurements relayed from
downhole sensors 50 in real time. The foam quality values are
calculated by control system 30 and displayed. For example, control
system 30 can be used to provide an API Logs template on which the
calculated values are displayed as API logs. An operator can enter
the boundary values (see graph lines 72) to provide an indication
of the suitable range for calculated foam quality values. Movement
of the foam quality values outside of the boundaries is an
indicator of a downhole event requiring changes to the treatment
operation. Control system 30 can be used to influence or control
the foam quality by changing aspects of the well treatment
operation.
[0045] An additional example of a downhole property that can be
used as an indicator of a specific downhole event is estimated
bottom hole pressure at formation depth while acquisition is
running. The calculation is based on the following parameters:
bottom hole pressure measurement obtained from the downhole sensors
50; true vertical depth (TVD) where bottom hole pressure (iBHP) is
based on the coiled tubing depth and the trajectory information
entered as borehole surveys; TVD of the location where bottom hole
pressure is calculated, based on the measured depth entered by user
and trajectory information; and density of the fluid below the
tool. It should be noted the density is initially entered as a
fixed parameter, but this parameter can change during a treatment
job which can affect the parameter calculations. Bottom hole
pressure at formation depth (cBHP) can be calculated with the
following formula:
cBHP=iCTBHP+w*(cDepth.sub.tvd-ctDepth.sub.tvd)
[0046] Calculated bottom hole pressure can be monitored versus
formation pressure and fracturing pressure, which can be entered
into control system 30 by an operator. The calculated bottom hole
pressure, formation pressure, and fracturing pressure also can be
displayed on horizontal time log 68. As illustrated in FIG. 3, the
calculated bottom hole pressure can be determined for a plurality
of well zones 74 in which each zone has its own depth, fracturing
pressure and formation pressure. Again, the appropriate values for
each of these well zones 74 can be entered into control system
30.
[0047] Downhole properties/measurements also can provide an under
balance/overbalance indicator in real time. In this example, the
measured downhole property may comprise pressure which is monitored
by a suitable downhole sensor 50 and transmitted to the surface
data acquisition, analysis and control system 30. The measurement
can be used to predict bottom hole pressure (cBHP) at formation
depth in different zones. Differences in the bottom hole
calculation can arise from differences in fluid density.
Accordingly, an operator can select different fluids, and thus
different fluid densities, for each well zone 74 to enable
independent pressure calculations in each well zone 74. Fluid types
can be entered by the operator via graphical user interface 62 or
another suitable input device. The calculated bottom hole pressure
is used, along with formation properties, to provide indicators to
the operator regarding the pressure condition at defined well
zones. In this example, pore pressure can be entered as well as the
fracturing pressure for each zone. Control system 30 is then able
to create different pressure intervals that are indicative of
specific downhole events relative to the under balance/over balance
condition of the well. Although the information can be displayed in
a variety of formats, one format example is illustrated in FIG. 4
and provides minimum and maximum pressure conditions for a
plurality of listed downhole events 76. For example, pressure
balance ranges can be provided for under balanced, balanced,
overbalanced, fracture warning, and fracture conditions.
[0048] The minimum and maximum boundaries listed in FIG. 4 for
downhole events 76 are only examples of initial suggestions/values
that can be provided by control system 30. Additionally, an
operator can interface with control system 30 to change values
and/or to turn off or turn on the monitoring of specific well
zones. Additionally, a variety of graphs can be displayed to show
the historical progress of one or more well zone conditions over
time.
[0049] One example of a suitable graphical user interface 62 is
illustrated in FIG. 5. In this example, the interface 62 provides
an indicator 78 that points to selected downhole conditions, e.g.
under balance/over balance conditions, as represented by pressure
segments 80. The pressure segments 80 may correspond with ranges
for predicting downhole events 76. In this example, a bar graph
section 82 is used to illustrate a history of the wellbore
condition according to colored indicators that match the color of
pressure segments 80. Additionally, the graphical user interface 62
provides an input 84 for starting and/or stopping the monitoring of
specific well zones. A fluid selection window 86 also enables the
selection of fluid for use in making bottom hole pressure
calculations at each well zone, as described above. Additionally, a
zone property input 88 can be used to select or change a variety of
values used to characterize a specific reservoir or interval. For
example, changes can be made to the values for pore pressure,
fracture pressure, and the pressure ranges for a wellbore condition
(over balanced, under balanced, and other conditions). A display
area 90 also can be used to display a variety of additional
information, such as the depth of specific well zones.
[0050] Similar interfaces can be displayed simultaneously on one or
more of the graphical user interfaces 62. In the example
illustrated in FIG. 6, interfaces are displayed for four different
well zones, although the number of interfaces displayed can be
greater or lesser depending on the treatment application and the
number of well zones. In the embodiment of FIG. 6, each interface
provides an under balanced/over balanced indicator for each zone,
however multiple interfaces can be provided to indicate the
occurrence of other or additional downhole events.
[0051] Pressure and/or other downhole properties can be monitored
and analyzed as an indicator of the level of differential pressure
between the inside and outside of coiled tubing 36. Sensors 50
comprise pressure sensors that are capable of measuring the
pressure inside and outside of the coiled tubing 36 which can serve
as predictive indicators of downhole events related to use of the
coiled tubing. In some well treatment operations, such as those in
which treatment tool 32 comprises a nozzle at the end of coiled
tubing 36, it is desirable to maintain the differential pressure
within a certain range. Having the differential pressure too low
can cause coiled tubing to collapse. However, having the
differential pressure too high can cause the coiled tubing to
burst.
[0052] When using continuous feedback system 22 to monitor pressure
inside and outside of the coiled tubing, an operator is prompted to
enter three pressure ratings into control system 30 via, for
example, graphical user interface 62. The three pressure ratings
may comprise a coiled tubing design delta pressure rating for the
specific coiled tubing used in the well treatment operation. The
three pressure ratings also may comprise a collapse rating for the
coiled tubing and a burst rating for the coiled tubing.
[0053] In one embodiment, control system 30 uses the ratings to
create a plurality of intervals/downhole events 92, as illustrated
in FIG. 7. In one example, the intervals 92 are displayed with
associated color coding. As illustrated, the plurality of intervals
92 are established for differential pressure states related to the
coiled tubing 36 and may include collapse, near collapse, low
pressure, operating pressure, high pressure, and burst states as
well as additional states.
[0054] In this embodiment, a variety of graphical user interfaces
62 also can be used. One example of a suitable graphical user
interface 62 is illustrated in FIG. 8 and includes a scale 94
having a plurality of color-coded markers 96 indicating the
differential pressure levels for the various differential pressure
states. Additionally, the graphical user interface 62 comprises a
variety of inputs 98 that can be used to enter values for pressure
ratings and pressure intervals. As with other graphical user
interfaces discussed above, a variety of additional displays,
inputs, and screens can be incorporated into the illustrated
interface.
[0055] Another example of a downhole event that can be detected in
real time based on monitoring of one or more downhole properties
involves static bottom hole pressure. In some embodiments, wellbore
fluid density and pore pressure (formation pressure) can be used in
the cBHP calculation and the indicators as user entries. Control
system 30 can provide a facility and procedure to estimate these
values to prevent false user entries. If the well condition prior
to the well treatment is such that a steady fluid column has been
established, e.g. after a period of shut-in, the formation pressure
is equal to the static bottom hole pressure, which can be
determined by the fluid level and the wellbore fluid density.
Wellbore fluid density can be estimated at the start of the job as
the coiled tubing is run-in-hole by using the bottom hole pressure
measurement from an appropriate sensor 50 on treatment tool 32.
[0056] According to one procedure, calculations are made to
estimate the wellbore fluid density and the pore pressure. In this
procedure, the pumps delivering treatment fluid downhole are turned
off or set as low as reasonably possible. Subsequently, a coiled
tubing depth correction is performed. Assuming the well is not
full, a noticeable slope change is expected when the coiled tubing
meets the liquid level in the well. When the end of the coiled
tubing enters the liquid in the well, the slope of the pressure
curve is used to give the density of the wellbore liquid. As the
coiled tubing is moved downhole, the liquid level continues to rise
due to the volume displaced by the coiled tubing but this can be
taken into account in a density computation. As illustrated by the
graphs in FIGS. 9 and 10, the measurement of pressure versus true
vertical depth varies depending on whether the well is topped off
before running the coiled tubing in hole. When the coiled tubing
string 24 enters liquid in the well, the slope of the "measured
pressure vs. TVD" changes fairly abruptly, as illustrated in FIG.
9. Otherwise, the slope remains more constant, as illustrated in
FIG. 10.
[0057] In this example, an operator can enter the liquid level
(TVD.sub.0) into control system 30, and then enter/select whether
or not the well is to be topped off with liquid. The control system
30 is designed to compute and plot the gradient (Gr) while
running-in-hole when there is no pumping or minimal pumping of
treatment fluid downhole. As the tubing string 24 moves into the
fluid within the well, the fluid level changes, as illustrated in
FIG. 11, and this can affect the gradient. In FIG. 11, D.sub.tubing
represents the overall diameter of the tubing; D.sub.CT represents
the diameter of the coiled tubing; and h represents liquid level
rise. In a first case where the wellbore is not full, liquid level
changes occur during deployment of tubing string 24 as a result of
the coiled tubing volume. The liquid level rise can be determined
as follows:
h ( D tubing 2 - D CT 2 ) = D CT 2 ( TVD - TVD 0 ) ##EQU00001## h =
( TVD - TVD 0 ) D CT 2 ( D tubing 2 - D CT 2 ) ##EQU00001.2##
The liquid height above the coiled tubing end is determined by:
L = ( TVD - TVD 0 ) + h = ( TVD - TVD 0 ) D tubung 2 D tubing 2 - D
CT 2 ##EQU00002##
The gradient Gr may then be computed as follows while
TVD<TVDlimit (TVDlimit is the coiled tubing depth when the fluid
level reaches the top):
Gr = P - WHP L , TVD limit = TVD 0 D tubing 2 D CT 2
##EQU00003##
WHP equals wellhead pressure.
[0058] In a second case, when TVD>TVDlimit and alternatively
when the wellbore is topped off, the gradient is computed as
follows:
Gr = P - WHP TVD . ##EQU00004##
[0059] In FIG. 10, a graph is provided illustrating the gradient Gr
plotted against time by graph line 100. Additionally, the graph
illustrates a pressure graph line 102 and a TVD graph line 104
plotted against time. The graph, or a similar output, can be
computed and displayed via control system 30. The calculated
gradient Gr is monitored to determine when a stable gradient
baseline Gr.sub.0 is achieved. The Gr.sub.0 value can be entered in
a designated field by an operator, or control system 30 can be used
to automatically record the value. The control system 30 uses this
value in computing wellbore fluid density, RHO.sub.0, via, for
example, the following expression:
RHO 0 = Gr 0 gravity . ##EQU00005##
Reservoir pressure estimates can be computed at selected reservoir
depths, such as TVDres1 and TVDres2 as follows:
P.sub.res1=Gr.sub.0(TVD.sub.res1-TVD.sub.0)
P.sub.res2=Gr.sub.0(TVD.sub.res2-TVD.sub.0) [0060] . . .
[0061] One example of a display format/graphical user interface 62
is illustrated in FIG. 13 and provides a representation of a
gradient baseline 106. Additional plots of pressure 108 and TVD 110
also can be displayed. In this embodiment, a user/operator is able
to select a gradient baseline by selecting and moving a displayed
drag bar 112. A related display window 114 can be used to display
corresponding parameters, such as density and gradient values as
drag bar 112 is moved or changed. One or more additional displays
116 also can be used to display a variety of other parameters, such
as calculated pore pressure, at different zones. By way of further
example, an input area 118 can be provided to enable an operator to
enter the liquid level for a given wellbore. These and other
features may be incorporated into the graphical user interface of
control system 30.
[0062] Some applications of the present system and methodology
provide diversion and stimulation indicators based on measurements
from downhole tools, such as treatment tool 32, via sensors 50. By
way of example, when the injection rate of treatment fluid is
non-zero and constant, the rate of bottom hole pressure change can
be used to determine if the diversion or stimulation occurring is
based on the fluid pumped during the treatment procedure. In one
example, the following matrix can be used to determine the state of
diversion or stimulation downhole:
TABLE-US-00001 DIVERSION INDICATOR Diversion No Diversion Rate of
BHP change slope > 5 psi/min slope < 5 psi/min or and p
increase > 100 psi p increase < 100 psi
TABLE-US-00002 Stimulation Indicator Acid no longer Stimulation
effective Acid ineffective Rate of slope < slope > -5 psi/min
slope > -5 psi/min BHP change -5 psi/min and and p decrease >
100 psi p decrease < 100 psi
[0063] The bottom hole pressure (BHP) value can be calculated via
control system 30 for specific well zones as defined or selected by
an operator via a suitable graphical user interface. The selection
of bottom hole pressure values helps ensure that BHP is calculated
for a fixed point and is not affected by coiled tubing movement. In
some applications, the BHP measurement can have substantial noise,
but a variety of algorithms can be used to smooth the data. For
example, a smoothing algorithm can be based on averaging over a
sliding window. A default sliding window size for the
averaging/smoothing of data can be selected, e.g. 30 seconds, and
the rate can be calculated by comparing the current average value
with the value calculated at the previous interval, e.g. 30 second
interval.
[0064] The threshold values used in the matrix provided above are
the default values and can be changed by an operator. The control
system 30 enables the operator to save modified values for use in
other well treatment jobs or for later analysis. In one embodiment,
the graphical user interface displays a diversion indicator that
becomes "live" only when a diverter is exiting the coiled tubing
end. Similarly, a stimulation indicator becomes "live" only when an
acid is exiting the coiled tubing end.
[0065] Other applications of the present system and methodology
provide a warning to an operator if downhole measurements via, for
example, sensors 50 indicate the possibility of a stuck or embedded
coiled tubing 36 or treatment tool 32. The determination may be
made based on a variety of input variables, such as carrier fluid
type; carrier fluid density; fill type and density; reservoir
pressure; reservoir depth (interval); completion--casing and tubing
size and depth; coiled tubing outer diameter; clean out speed;
sweep speed; and other related parameters. The carrier treatment
fluid may be water, brine, gelled fluid, foam, slick water,
energized fluid, nitrogen, carbon dioxide, and other suitable
carrier fluids. By way of example, the following list provides fill
types and corresponding densities:
TABLE-US-00003 Fill type S.G. Sand 2.65 Carbolite 2.73 Intermediate
Strength Ceramic 3.20 High Strength Ceramic 3.50 Sintered Bauxite
3.45 Resin Coated Sand 2.55 Resin Coated Ceramic 2.73 Calcium
Carbonate Scale 2.70 Calcium Sulfate Scale 2.30 Barium Sulfate
Scale 4.50
[0066] Determination of the potential for being stuck during an
operation is evaluated based on matrices that establish a defined
set of parameters indicative of the risk for being stuck. The
parameters can include, for example, angular velocity,
concentration of solid in suspension (volume), bottom hole pressure
gradient rate of change, coiled tubing weight variations,
over/under balance, run-in-hole/pull-out-of-hole speed, and other
parameters.
[0067] Several matrix examples are provided in FIGS. 14 through 17.
In FIG. 14, for example, a water/brine risk matrix is provided. In
FIG. 15, one example of a gelled fluid matrix is provided.
Similarly, FIG. 16 provides one example of a foam risk matrix. FIG.
17 provides one example of a nitrogen matrix. Within these
matrices, a variety of terms are listed that can be used in system
or method calculations. For example, PPA refers to the pounds of
solids added per gallon of carrier fluid; CS is the clean out speed
in feet per minute (value can be input by operator); SS refers to
the sweep speed in feet per minute (value can be input by
operator); Y is the density corresponding to a low risk PPA limit;
and Z is the density corresponding to a high risk PPA limit. The Y
and Z PPG calculations can be made using the following formula:
PPG = ( Carrier_fluid _density ) + PPA 1 + PPA ( SG_fill ) ( 8.32 )
- ( Carrier_fluid _density ) ##EQU00006##
Realtime PPG can be determined by:
PPG = ( PTC_pressure ) ( Corrected_depth ) ( 0.052 ) - (
Carrier_fluid _density ) ##EQU00007##
[0068] Referring generally to FIG. 18, another example of a
graphical user interface 62 is illustrated. In this example, the
graphical user interface displays the stuck/embedding potential via
a risk bar 120. Additionally, a plurality of input windows 122 are
provided to enable an operator to enter the various parameters used
in calculating the risk as discussed above with respect to FIGS. 14
through 17.
[0069] As described above, well treatment system 20 can be
constructed in a variety of configurations for use in many
environments and applications. Additionally, control system 30 can
be constructed with a central controller or a plurality of
cooperating controllers located proximate the well site or remote
from the well site. A variety of sensors 50, treatment tools 32,
and tubing 36 also can be used depending on the treatment operation
and the properties monitored in real time. The data obtained and
provided by sensors 50 also can be used in a variety of formulas,
algorithms, and models to aid in the detection of one or more
downhole events based on the monitoring of one or more downhole
properties. The control system 30 and a sensors 50 cooperate to
provide a continuous feedback system utilizing a real time closed
loop interpretation technique that enables control system 30 to
instantaneously synchronize and adjust well treatment actions at a
surface location, e.g. adjust pumping equipment 42, to affect a
downhole event. The data can be used to detect the actual
occurrence or the potential for specific events. Control system 30
can be programmed to automatically react in specific ways to the
detected or calculated properties for exercising control over the
treatment operation in a manner that influences or controls the
downhole event.
[0070] Accordingly, although only a few embodiments of the present
invention have been described in detail above, those of ordinary
skill in the art will readily appreciate that many modifications
are possible without materially departing from the teachings of
this invention. Such modifications are intended to be included
within the scope of this invention as defined in the claims.
* * * * *