U.S. patent application number 11/738327 was filed with the patent office on 2008-10-23 for system and method for crossflow detection and intervention in production wellbores.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. Invention is credited to Chee M. Chok, Jaedong Lee, Xin Liu, Clark Sann, Brian L. Thigpen, Guy P. Vachon, Garabed Yeriazarian.
Application Number | 20080257544 11/738327 |
Document ID | / |
Family ID | 39876171 |
Filed Date | 2008-10-23 |
United States Patent
Application |
20080257544 |
Kind Code |
A1 |
Thigpen; Brian L. ; et
al. |
October 23, 2008 |
System and Method for Crossflow Detection and Intervention in
Production Wellbores
Abstract
A system and method for managing a production from a wellbore
that includes taking measurements relating to one or more selected
parameters for each of the production zones over a time period and
determining the occurrence of the cross flow in the wellbore using
a trend of the one or more of the measurements. The system includes
a processor that receives information relating to the measurements
made over time relating to the selected parameters, wherein the
processor determines or predicts the occurrence of the cross flow
from a trend of at least one of the measurements.
Inventors: |
Thigpen; Brian L.; (Houston,
TX) ; Vachon; Guy P.; (Houston, TX) ;
Yeriazarian; Garabed; (Katy, TX) ; Lee; Jaedong;
(Katy, TX) ; Chok; Chee M.; (Houston, TX) ;
Sann; Clark; (Houston, TX) ; Liu; Xin; (Katy,
TX) |
Correspondence
Address: |
MADAN, MOSSMAN & SRIRAM, P.C.
2603 AUGUSTA DRIVE, SUITE 700
HOUSTON
TX
77057-5662
US
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
39876171 |
Appl. No.: |
11/738327 |
Filed: |
April 20, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
11737402 |
Apr 19, 2007 |
|
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|
11738327 |
|
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Current U.S.
Class: |
166/250.01 ;
702/12 |
Current CPC
Class: |
E21B 43/14 20130101;
E21B 47/10 20130101 |
Class at
Publication: |
166/250.01 ;
702/12 |
International
Class: |
E21B 47/10 20060101
E21B047/10 |
Claims
1. A method of detecting cross flow in a wellbore, comprising:
taking at least one first measurement indicative of a first
parameter of a first production zone; taking at least one second
measurement indicative of a second parameter of a second production
zone; and determining an occurrence of a cross flow condition from
a trend relating to at least one of the first measurement and the
second measurement.
2. The method of claim 1, wherein the first parameter or the second
selected parameter is selected from a group consisting of: (i)
pressure; (ii) temperature; and (iii) fluid flow rate.
3. The method of claim 1, wherein determining the occurrence of a
cross flow condition comprises using a nodal analysis to predict
the occurrence of the cross flow condition.
4. The method of claim 1 further comprising: taking the at least
one first measurement and the at least one second measurement over
a time period; determining a rate of change of one of the at least
one first measurement and the at least one second measurement; and
predicting the occurrence of the cross flow condition based at
least in part on the determined rate of change of the at least one
of the at least one first measurement and the at least one second
measurement.
5. The method of claim 1 further comprising sending an alarm
condition indicating the cross flow condition.
6. The method of claim 1 further comprising determining a change in
an operation of at least one flow control device associated with
the wellbore, which change when made is expected to at least reduce
an effect of the cross flow condition.
7. The method of claim 1 further comprising performing at least one
operation to reduce an effect of the cross flow, which operation is
selected from a group consisting of: (i) closing a choke; (ii)
changing frequency of an electrical submersible pump; (iii)
operating a valve; (iv) changing supply amount of an additive to
the wellbore; (v) closing at least one of the first and second
production zones; (vi) isolating at least one of the first and
second production zones; (vi) decreasing a surface pressure; and
(vii) opening a surface choke.
8. A computer-readable medium accessible to a processor for
executing instructions contained in a computer program embedded in
the computer-readable medium, the computer program comprising:
instructions to receive information relating to a first measurement
indicative of a selected parameter of a first production zone and
second measurement indicative of a selected parameter of a second
production zone; and instructions to determine occurrence of a
cross flow condition from a trend relating to at least one of the
first measurement and the second measurement.
9. The computer-readable medium of claim 8, wherein the selected
parameter is chosen from a group consisting of: (i) pressure; (ii)
temperature; and (iii) fluid flow rate.
10. The computer-readable medium of claim 8, wherein the computer
program further comprises instructions to use a nodal analysis to
determine the occurrence of the cross flow condition.
11. The computer-readable medium of claim 8, wherein the first
measurement and the second measurement are taken over a time
period, and wherein the computer program further comprises
instructions to determine a rate of change of one of the first
measurement and the second measurement; and instructions to
determine the occurrence of the cross flow condition based at least
in part on the determined rate of change of at least one of the
first measurement and the second measurement.
12. The computer-readable medium of claim 8, wherein the computer
program further comprises instructions to generate one or more
recommendations that include at least one of: (i) close a choke;
(ii) change frequency or speed of an electrical submersible pump;
(iii) operate a valve; (iv) change supply amount of an additive to
the wellbore; (v) close a production zone; (vi) isolate a
production zone; (vi) decrease surface pressure; and (vii) open a
surface choke.
13. An apparatus for managing production from a wellbore,
comprising: a processor that receives an input relating to a first
measurement of a selected parameter corresponding to a first
production zone and a second measurement relating to a selected
parameter for the second production zone, each of the first and the
second production zones producing a formation fluid into the
wellbore, wherein the processor determines an occurrence of a cross
flow condition in the wellbore from a trend relating to at the
least one of the first measurement and the second measurement.
14. The apparatus of claim 13, wherein the selected parameters for
the first production zone and the second production zone are chosen
from a group consisting of: (i) pressure; (ii) temperature; and
(iii) fluid flow rate.
15. The apparatus of claim 13, wherein the processor uses a model
and performs a nodal analysis to determine the occurrence of the
cross flow condition.
16. The method of claim 13, wherein the first measurement and the
second measurement each is taken over a time period and wherein the
processor: determines a rate of change of one of the first
measurement and the second measurement; and determines the
occurrence of the cross flow condition based at least in part on
the determined rate of change of at least one of the first
measurement and the second measurement.
17. The apparatus of claim 13, wherein the processor further sends
an alarm condition in response to the determination of cross flow
condition.
18. The apparatus of claim 13, wherein the processor further
determines a desired change in an operation of at least one device
associated with the wellbore, which change when made is expected to
at least reduce an adverse effect of the cross flow condition.
19. The apparatus of claim 13, wherein the processor further sends
signals for performing at least one operation in response to the
determination of the occurrence of the cross flow condition, which
operation is selected from a group consisting of: (i) operating a
choke; (ii) changing a frequency or speed of an electrical
submersible pump; (iii) operating a downhole valve; (iv) changing
supply amount of an additive to the wellbore; (v) closing at least
one of the production zones; (vi) isolating at least one of the
production zones; (vi) decreasing a surface pressure; and (vii)
opening a surface choke.
20. The apparatus of claim 13, further comprising a computer
program on a computer-readable medium accessible to the processor
for executing instructions contained in the computer program,
wherein the computer program includes a model to perform nodal
analysis to predict the occurrence of the cross flow.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation-in-part of U.S. patent
application Ser. No. 11/737,402 filed Apr. 19, 2007.
BACKGROUND OF THE DISCLOSURE
[0002] 1. Field of the Disclosure
[0003] This disclosure relates generally to detecting cross flow in
production wellbores and for managing production of fluids from the
wellbores in response to the detection of the cross flow.
[0004] 2. Background of the Art
[0005] Wellbores are often drilled through formations that include
two or more production zones. Such wells are typically completed by
placing a casing along the wellbore length and perforating the
casing adjacent each such production zone to extract the formation
fluids (such as hydrocarbons) into the wellbore. These production
zones are sometimes separated from each other by installing a
packer between the production zones. Fluid from each production
zone entering the wellbore is drawn into a tubing that runs to the
surface. Normally, the pressure in the wellbore proximate a lower
production zone is greater than the pressure proximate an upper or
shallower production zone, which forces the fluid from the lower
and upper production zones to the surface.
[0006] Due to anomalies in the formations surrounding the wellbore,
sometimes the pressure proximate the upper production zone can
exceed the pressure proximate the lower production zone, causing
the fluid from the upper production zone to flow toward the lower
production zone, a phenomenon referred to as the cross flow. In
such situations, the fluid from the lower production zones may not
flow to the surface. Cross flow is often detected a certain time
after it has occurred and in some cases it may cause damage to the
equipment and devices in the wellbore, including damage to the
electrical submersible pump (when present in the wellbore) and
other wellbore devices and in other cases it may damage the
wellbore and the formations surrounding the wellbore. Therefore,
there is a need for an improved system and method that detect the
cross flow and takes appropriate corrective actions at the
wellsite.
SUMMARY OF THE DISCLOSURE
[0007] In one aspect, cross flow is detected by: taking at least
one first measurement indicative of a selected parameter of a first
production zone, taking at least one second measurement indicative
of the selected parameter of a second production zone, and
determining occurrence of the cross flow a trend relating to at
least one of the first measurement and the second measurement. The
selected parameter may pressure, temperature or fluid flow rate.
The method may use nodal analysis and/or a neural network to
predict the occurrence of the cross flow. The method may determine
the cross flow from the rate of change of one of the parameters,
such as the rate of change of the pressure corresponding to the
upper and/or the lower zone.
[0008] Upon detection or based on the predicted cross flow, the
method may determine changes that may be made to the operation of
one or more devices, which changes when made may reduce or
eliminate the cross flow condition or its effects. In one aspect,
certain devices relating to the wellbore may be automatically set
to new operating positions. The changes may include actions such as
(i) closing a choke; (ii) changing frequency of an electrical
submersible pump pumping fluid; (iii) changing a supply amount of
an additive to the wellbore; (v) closing a zone; (vi) isolating a
zone; (vi) decreasing surface pressure; and (vii) opening a surface
choke.
[0009] The apparatus utilized to detect the cross flow may include
a processor that receives an input relating to a first measurement
of a selected parameter corresponding to a first production zone
and a second measurement of the selected parameter relating to a
second production zone when each of the production zones is
producing a formation fluid into a well. The processor processes
data relating to the measurements to predict or detect the cross
flow. The selected parameter may be chosen from a group consisting
of: (i) pressure; (ii) temperature; and (iii) fluid flow rate. The
processor in one aspect may use a model and performs a nodal
analysis to determine the occurrence of the cross flow condition.
The measurements may be made continuously or periodically over
time. In one aspect, the processor may determine a rate of change
or trend of at least one of the first measurements and the second
measurements and detect or predict the occurrence of the cross flow
based at least in part on the determined trend or the rate of
change. In one aspect, the processor may send one or more alarm
conditions that also may be displayed on a display for use by an
operator and such conditions may be sent to a remote location via
any suitable communication link, including the Internet.
[0010] The processor also may be configured to suggest adjustments
to one or more operating parameters of the wellbore to limit or
eliminate the negative impact of an anticipated or actual cross
flow condition, which may include, but not are limited to (i)
operating a choke; (ii) changing frequency of an electrical
submersible pump pumping fluid; (iii) operating a sliding sleeve
valve; (iv) changing a supply of the amount of an additive to the
wellbore; (v) closing of a zone; (vi) isolating a zone; (vi)
decreasing the surface pressure; and (vii) opening a surface
choke.
[0011] One or more computer models and computer programs may be
stored in a computer-readable media that is accessible to the
processor. The processor executes the instructions contained in the
computer programs to perform one or more of the functions and
methods described herein. In one aspect, the programs include a
model that uses a nodal analysis or neural network to detect or
predict the occurrence of the cross flow, determine the suggested
changes and perform a net present value based on the new
settings.
[0012] Examples of the more important features of system and method
for cross flow detection and intervention in production wells have
been summarized rather broadly in order that the detailed
description thereof that follows may be better understood, and in
order that the contributions to the art may be appreciated. There
are, of course, additional features that will be described
hereinafter and which will form the subject of the claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] For a detailed understanding of the system and method for
detecting cross flow and well intervention described herein,
reference should be made to the following detailed description of
the embodiments, taken in conjunction with the accompanying
drawings, in which like elements generally have been given like
numerals, wherein:
[0014] FIGS. 1A and 1B collectively show a schematic diagram of a
production wellbore system for producing fluid from multiple
production zones;
[0015] FIG. 2 is an exemplary functional diagram of a control
system 200 that may be utilized to perform various measurements and
data to predict an occurrence of a cross-flow condition relating to
a production well system, including the well system shown in FIGS.
1A and 1B; and
[0016] FIG. 3 is an exemplary graph showing pressure measurements
over time corresponding to the exemplary production zones shown in
FIG. 1A that may be used for detecting cross flow.
DETAILED DESCRIPTION OF THE DISCLOSURE
[0017] FIGS. 1A and 1B collectively show a schematic diagram of a
production well system 10. FIG. 1A shows a production well 50 that
has been configured using exemplary equipment, devices and sensors
that may be utilized to implement the concepts and methods
described herein. FIG. 1B shows exemplary surface equipment,
devices, sensors, controllers, computer programs, models and
algorithms that may be utilized to: detect and/or predict an
occurrence of a cross flow condition; send appropriate messages and
alarms to an operator; determine adjustments to be made or actions
to be taken relating to the various operations of the well 50 to
mitigate or eliminate negative effects of the potential or actual
occurrence of the cross flow condition; automatically control any
one or more of the devices or equipment in the system 10; establish
a two-way communication with one or more remote locations and/or
controllers via appropriate links, including the Internet, wired or
wireless links; and automatically take one or more actions.
[0018] FIG. 1A shows a well 50 formed in a formation 55 that is
producing formation fluid 56a and 56b from two exemplary production
zones 52a (upper production zone) and 52b (lower production zone)
respectively. The well 50 is shown lined with a casing 57 that has
perforations 54a adjacent the upper production zone 52a and
perforations 54b adjacent the lower production zone 52b. A packer
64, which may be a retrievable packer, positioned above or uphole
of the lower production zone perforations 54a isolates the lower
production zone 52b from the upper production zone 52a. A screen
59b adjacent the perforations 54b the well 50 may be installed to
prevent or inhibit solids, such as sand, from entering into the
wellbore from the lower production zone 54b. Similarly, a screen
59a may be used adjacent the upper production zone perforations 59a
to prevent or inhibit solids from entering into the well 50 from
the upper production zone 52a.
[0019] The formation fluid 56b from the lower production zone 52b
enters the annulus 51a of the well 50 through the perforations 54a
and into a tubing 53 via a flow control valve 67. The flow control
valve 67 may be a remotely control sliding sleeve valve or any
other suitable valve or choke that can regulate the flow of the
fluid from the annulus 51a into the production tubing 53. An
adjustable choke 40 in the tubing 53 may be used to regulate the
fluid flow from the lower production zone 52b to the surface 112.
The formation fluid 56a from the upper production zone 52a enters
the annulus 51b (the annulus portion above the packer 64a) via
perforations 54a. The formation fluid 56a enters production tubing
or line 45 via inlets 42. An adjustable valve or choke 44
associated with the line 45 regulates the fluid flow into the line
45 and may be used to adjust flow of the fluid to the surface 112.
Each valve, choke and other such device in the well may be operated
electrically, hydraulically, mechanically and/or pneumatically from
the surface. The fluid from the upper production zone 52a and the
lower production zone 52b enter the line 46. FIGS. 1A and 1B
collectively show a schematic diagram of a production wellbore
system 10 that includes various flow control devices, sensors in
the wellbore and the surface, controllers, computer programs and
algorithms that may be used collectively to implement the methods
and concepts described herein according to one embodiment of the
disclosure. FIG. 1A shows a production wellbore 50 that has been
configured using exemplary equipment, devices and sensors that may
be utilized to implement the concepts and methods described herein.
FIG. 1B shows exemplary surface equipment, devices, sensors,
controllers and computer programs that may be utilized to detect or
predict a cross flow condition and to manage the operations of the
various devices in the system 10.
[0020] The formation fluid 56a enters production line 45 via inlets
42. An adjustable valve or choke 44 associated with the line 45
regulates the fluid flow into the line 45 and may be used to adjust
fluid flowing to the surface. Each valve, choke and other such
device in the wellbore may be operated electrically, hydraulically,
mechanically and/or pneumatically. The fluid from the upper
production zone 52a and the lower production zone 52b enter the
line 46.
[0021] In cases where the formation pressure is not sufficient to
push the fluid 56a and/or fluid 56b to the surface, an artificial
lift mechanism, such as an electrical submersible pump (ESP, a gas
lift system, a beam pump, a jet pump, a hydraulic pump or a
progressive cavity pump) may be utilized to pump the fluids from
the well to the surface 112. In the system 10, an ESP 30 in a
manifold 31 receives the formation fluids 56a and 56b and pumps
such fluids via tubing 47 to the surface 112. A cable 34 provides
power to the ESP 30 from a surface power source 132 (FIG. 1B) that
is controlled by an ESP control unit 130. The cable 134 also may
include two-way data communication links 134a and 134b, which may
include one or more electrical conductors or fiber optic links to
provide a two-way signals and data link between the ESP 30, ESP
sensors SE and the ESP control unit 130. The ESP control unit 130,
in one aspect, controls the operation of the ESP 30. The ESP
control unit 130 may be a computer-based system that may include a
processor, such as a microprocessor, memory and programs useful for
analyzing and controlling the operations of the ESP 30. In one
aspect, the controller 130 receives signals from sensors SE (FIG.
1A) relating to the actual pump frequency, flow rate through the
ESP, fluid pressure and temperature associated with the ESP 30 and
may receive measurements or information relating to certain
chemical properties, such as corrosion, scale, hydrate, paraffin,
emulsion, asphaltene, etc. and in response thereto or other
determinations control the operation of the ESP 30. In one aspect,
the ESP control unit 130 may be configured to alter the ESP pump
speed by sending control signals 134a in response to the data
received via link 134b or instructions received from another
controller. The ESP control unit 130 may also shut down power to
the ESP via the power line 134. In another aspect, ESP control unit
130 may provide the ESP related data and information (frequency,
temperature, pressure, chemical sensor information, etc.) to the
central controller 150, which in turn may provide control or
command signals to the ESP control unit 130 to effect selected
operations of the ESP 30.
[0022] A variety of hydraulic, electrical and data communication
lines (collectively designated by numeral 20 (FIG. 1A) are run
inside the well 50 to operate the various devices in the well 50
and to obtain measurements and other data from the various sensors
in the well 50. As an example, a tubing 21 may supply or inject a
particular chemical from the surface into the fluid 56b via a
mandrel 36. Similarly, a tubing 22 may supply or inject a
particular chemical to the fluid 56a in the production tubing via a
mandrel 37. Lines 23 and 24 may operate the chokes 40 and 42 and
may be used to operate any other device, such as the valve 67. Line
25 may provide electrical power to certain devices downhole from a
suitable surface power source.
[0023] In one aspect, a variety of other sensors are placed at
suitable locations in the well 50 to provide measurements or
information relating to a number of downhole parameters of
interest. In one aspect, one or more gauge or sensor carriers, such
as a carrier 15, may be placed in the production tubing to house
any number of suitable sensors. The carrier 15 may include one or
more temperature sensors, pressure sensors, flow measurement
sensors, resistivity sensors, sensors that provide information
about density, viscosity, water content or water cut, and chemical
sensors that provide information about scale, corrosion, paraffin,
hydrate, asphaltene, etc. Density sensors may be fluid density
measurements for fluid from each production zone and that of the
combined fluid from two or more production zones. The resistivity
sensor or another suitable sensor may provide measurements relating
to the water content or the water cut of the fluid mixture received
from each production zones. Other sensors may be used to estimate
the oil/water ratio and gas/oil ratio for each production zone and
for the combined fluid. The temperature, pressure and flow sensors
provide measurements for the pressure, temperature and flow rate of
the fluid in the line 53. Additional gauge carriers may be used to
obtain pressure, temperature and flow measurements, water content
relating to the formation fluid received from the upper production
zone 52a. Additional downhole sensors may be used at other desired
locations to provide measurements relating to chemical
characteristics of the downhole fluid, such as paraffin, hydrate,
sulfide, scale, corrosion, asphaltene, emulsion, etc. Additionally,
sensors Sl-Sm may be permanently installed in the wellbore 50 to
provide acoustic or seismic measurements, formation pressure and
temperature measurements, resistivity measurements and measurements
relating to the properties of the casing 51 and formation 55. Such
sensors may be installed in the casing 57 or between the casing 57
and the formation 55. Additionally, the screen 59a and/or screen
59b may be coated with tracers that are released due to the
presence of water, which tracers may be detected at the surface or
downhole to detect and/or predict the occurrence of a cross flow
condition. Sensors also may be provided at the surface, such as a
sensor for measuring the water content in the received fluid, total
flow rate for the received fluid, fluid pressure at the wellhead,
temperature, etc.
[0024] In general, sufficient sensors may be suitably placed in the
well 50 to obtain measurements relating to each desired parameter
of interest. Such sensors may include, but are not limited to,
sensors for measuring pressures corresponding to each production
zone, pressure along the wellbore, pressure inside the tubing
carrying the formation fluid, pressure in the annulus, temperatures
at selected places along the wellbore, fluid flow rates
corresponding to each of the production zones, total flow rate,
flow through the ESP, ESP temperature and pressure, chemical
sensors, acoustic or seismic sensors, optical sensors, etc. The
sensors may be of any suitable type, including electrical sensors,
mechanical sensors, piezoelectric sensors, fiber optic sensors,
optical sensors, etc. The signals from the downhole sensors may be
partially or fully processed downhole (such as by a microprocessor
and associated electronic circuitry that is in signal or data
communication with the downhole sensors and devices) and then
communicated to the surface controller 150 via a signal/data link,
such as link 101. The signals from downhole sensors may be sent
directly to the controller 150 as described in more detail
herein.
[0025] Referring back to FIG. 1B, the system 10 is further shown to
include a chemical injection unit 120 at the surface for supplying
additives 113a into the well 50 and additives 113b to the surface
fluid treatment unit 170. The desired additives 113a from a source
116a (such as a storage tank) thereof may be injected into the
wellbore 50 via injection lines 21 and 22 by a suitable pump 118,
such as a positive displacement pump. The additives 113a flow
through the lines 21 and 22 and discharge into the manifolds 30 and
37. The same or different injection lines may be used to supply
additives to different production zones. Separate injection lines,
such as lines 21 and 22, allow independent injection of different
additives at different well depths. In such a case, different
additive sources and pumps are employed to store and to pump the
desired additives. Additives may also be injected into a surface
pipeline, such as line 176 or the surface treatment and processing
facility such as unit 170.
[0026] A suitable flow meter 120, which may be a high-precision,
low-flow, flow meter (such as gear-type meter or a nutating meter),
measures the flow rate through lines 21 and 22, and provides
signals representative of the corresponding flow rates. The pump
118 is operated by a suitable device 122, such as a motor or a
compressed air device. The pump stroke and/or the pump speed may be
controlled by the controller 80 via a driver circuit 92 and control
line 122a. The controller 80 may control the pump 118 by utilizing
programs stored in a memory 91 associated with the controller 80
and/or instructions provided to the controller 80 from the central
controller or processor 150 or a remote controller 185. The central
controller 150 communicates with the controller 80 via a suitable
two-way link 85. The controller 80 may include a processor 92,
resident memory 91, for storing programs, tables, data and models.
The processor 92, utilizing signals from the flow measuring device
received via line 121 and programs stored in the memory 91
determines the flow rate of each of the additives and displays such
flow rates on the display 81. A sensor 94 may provide information
about one or more parameters of the pump, such the pump speed,
stroke length, etc. The pump speed or stroke, as the case may be,
is increased when the measured amount of the additive injected is
less than the desired amount and decreased when the injected amount
is greater than the desired amount. The controller 80 also includes
circuits and programs, generally designated by numeral 92 to
provide interface with the onsite display 81 and to perform other
desired functions. A level sensor 94a provides information about
the remaining contents of the source 116. Alternatively, central
controller 150 may send commands to controller 80 relating to the
additive injection or may perform the functions of the controller
80.
[0027] While FIGS. 1A and 1B illustrate one production well
penetrating through two production zones, however, it should be
understood that an oil field can include a variety of wells, each
interesting one or more production zones. The system, methods,
tools and devices shown and described herein may be utilized in any
number of such wells and may be configured to suit the particular
needs of the wells.
[0028] FIG. 2 shows a functional diagram of a production well
system 200 that may be utilized to detect and/or predict cross
flow, determine actions that may be taken to mitigate the effects
the cross flow condition, send messages to an operator and remote
locations, automatically take certain actions, compute production
rates, perform economic analysis and to perform other operations
relating to a production well system, including the well system 10
of FIGS. 1A and 1B.
[0029] System 200 includes a central control unit or controller 150
that includes one or more processors, such as a processor 152,
suitable memory devices 154 and associated circuitry 156 that are
configured to perform various functions and methods described
herein. The system 200 includes a database 230 stored in a suitable
computer-readable medium that is accessible to the processors 152.
The database 230 may include: (i) well completion data including,
but not limited to, the types and locations of the sensors in the
well, sensor parameters, types of devices and their parameters,
including choke type and sizes, choke positions, valve type and
sizes, valve positions, casing thickness, cement thickness, well
diameter, well profile, etc.; (ii) formation parameters, such as
rock type for various formation layers, porosity, permeability,
mobility, resistivity, depth of each formation layer and production
zone, inclination, etc.; (iii) sand screen parameters; (iv) tracer
information; (v) ESP parameters, such as horsepower, frequency
range, operating pressure range, maximum pressure differential
across the ESP, operating temperature range, and a desired
operating envelope; (vi) historical well performance data,
including production rates over time for each production zone,
pressure and temperature values over time for each production zone
and wells in the same or nearby fields; (vii) current and prior
choke and valve settings; (viii) intervention and remedial work
information; (ix) sand and water content corresponding to each
production zone over time; (x) initial seismic data (two- or
three-dimensional maps) and updated seismic data (four-dimensional
seismic maps); (xi) waterfront monitoring data; (xii) microseismic
data that may relate to seismic activity caused by a fluid front
movement, fracturing, etc.; (xii) inspection logs, such as obtained
by using acoustic or electrical logging tools that provide an image
of the casing showing pits, gauges, holes, and cracks in the
casing, condition of the cement bond between the casing and the
well wall, etc.; and (xiii) any other data that may be useful for
detecting a cross flow, determining the health of the downhole
devices, determining the actions to be taken upon detection or
prediction of the cross flow, monitoring the effects of taking the
actions so as to recover the hydrocarbons at an enhanced or
optimized rate from the well 50.
[0030] During the life of a well, one or more tests, collectively
designated by numeral 224, are typically performed to estimate the
health of various well elements and various parameters of the
production zones and the formation layers surrounding the well.
Such tests may include, but are not limited to: casing inspection
tests using electrical or acoustic logs for determining the
condition of the casing and formation properties; well shut-in
tests that may include pressure build-up or pressure transients,
temperature and flow tests; seismic tests that may use a source at
the surface and seismic sensors in the well to determine water
front and bed boundary conditions; microseismic measurement
responsive to a downhole operation, such as a fracturing operation
or a water injection operation; fluid front monitoring tests;
secondary recovery tests, etc. All such test data 224 may be stored
in a memory and provided to the processor 152 for monitoring the
production from well 50, performing analysis for determining the
health of various equipment and for enhancing, optimizing or
maximizing production from the well 50 and the reservoir.
[0031] Additionally, the processor 152 of system 200 may
periodically or continually access the downhole sensor measurement
data 222, surface measurement data 226 and any other desired
information or measurements 228. The downhole sensor measurements
222 includes, but are not limited to: information relating to
pressure; temperature; flow rates; water content or water cut;
resistivity; density; viscosity; sand content; chemical
characteristics or compositions of fluids, including the presence,
amount and location of corrosion, scale, paraffin, hydrate and
asphaltene; gravity; inclination; electrical and electromagnetic
measurements; oil/gas and oil/water ratios; and choke and valve
positions. The surface measurements 226 include, but are not
limited to: flow rates; pressures; choke and valve positions; ESP
parameters; water content determined at the surface; chemical
injection rates and locations; tracer detection information,
etc.
[0032] The system 200 also includes programs, models and algorithms
232 embedded in one or more computer-readable media that are
accessible to the processor 152 to execute instructions contained
in the programs. The processor 152 may utilize one or more
programs, models and algorithms to perform the various functions
and methods described herein. In one aspect, the programs, models
and algorithms 232 may be in the form of a well performance
analyzer (WPA) 260 that is used by the processor 152 to analyze
some or all of the measurement data 222, 226, test data 224,
information in the database 230 and any other desired information
made available to the processor to detect and/or predict cross
flow, determining an action plan or set of desired actions to be
taken, simulate the effects of such actions, perform comparative
analysis between competing sets of potential action plans, monitor
the effects of the actual actions taken and perform an economic
analysis, such as a net present value analysis. The well
performance analyzer may use a forward looking model, such a nodal
analysis, neural network, an iterative process or another
algorithm.
[0033] Referring now to FIG. 1A, under normal operating conditions
of the well 50, pressure corresponding to the lower production zone
52b will be greater than the pressure corresponding to the upper
production zone 52a. Under such a condition, the formation fluid
56a from the upper production zone will flow toward the surface as
shown by arrows 77A. However, under certain conditions, the
formation pressure "Pu" corresponding to the upper production zone
52a may start to increase and eventually become greater than the
pressure "Pl" of the lower production zone 52b. As this pressure
shift occurs, the formation fluid from the upper production zone
starts to flow toward the lower production zone, as shown by the
arrows 77B. At some point in time the pressure Pu and Pl cross over
and the fluid from the upper production zone starts to flow
downhole.
[0034] FIG. 3 shows a hypothetical pressure graph 300 showing
pressure versus time corresponding to the upper and lower
production zones for a scenario under which a pressure cross-over
occurs. Pressure is shown along the vertical axis, while time is
shown along the horizontal axis. In graph 300, the pressure curve
202 corresponds to Pu (the pressure corresponding to the upper
production zone) and the pressure curve 204 corresponds to Pl, (the
pressure corresponding to the lower production zone). In the
example of FIG. 3, at approximately time 210 the pressure Pu starts
to increase and the pressure Pl starts to decrease. The two
pressures cross over at time 220 and Pu thereafter becomes greater
than Pl. Under such a scenario, the fluid produced by the upper
production zone may drain into the lower production zone, or the
fluid from the lower production zone may not be lifted to the
surface, thereby causing loss of hydrocarbons. Such a condition may
cause damage to one or more devices in the wellbore, such as the
ESP 30 and also may cause damage to a formation or the wellbore in
general. It should be appreciated that the scenario of FIG. 3 is
merely one of several scenarios under which a cross flow may
occur.
[0035] In the system 200, the controller 150, in one aspect,
continually monitors the pressures Pu and Pl, utilizes the well
performance analyzer 260 and detects the occurrence of a cross-flow
condition. The well performance analyzer may predict a potential
cross flow condition from the trend of the pressures Pu and Pl and
may estimate the time or time period and the severity of the
predicted occurrence of the cross-flow condition. The well
performance analyzer 260 may utilize a nodal analysis, neural
network, or other models and/or algorithms to detect or predict the
cross flow condition. The well performance analyzer may utilize
current measurements of pressure, flow rates, temperature,
historical, laboratory or other synthetic data to detect or predict
the cross flow condition and the actual or expected time of the
occurrence of the cross flow. The models may utilize or take into
account any number of factors, such as the: amount or percent of
percent pressure in the wellbore that is above the formation
pressure and the length of time for which such a pressure condition
has been present; rate of change of the pressures Pu and/or Pl;
actual Pl and Pu values; difference between the pressures Pl and
Pu; actual temperatures of the upper and lower production zones;
difference in the temperatures between the upper and lower
production zones; annulus (upper zone) being greater than the
pressure in the tubing (lower zone) while the lower zone is open
for producing fluids; flow measurements from each of the production
zones; a fluid flow downhole approaching a cross flow condition;
and other desired factors.
[0036] Upon the detection or prediction of a cross flow condition,
the processor 152 using the well performance analyzer 260 and other
programs 232 determines the action or actions that may be taken to
mitigate and/or eliminate the negative effects of the cross flow
condition. Such actions may include, but are not limited to:
altering flow from a particular production zone; shutting-in a
particular zone or the entire well; increasing fluid flow from one
production zone while decreasing the fluid from another production
zone; altering the operation of an artificial lift mechanism, such
as altering the frequency of an ESP; changing a chemical injection
rate; performing a secondary operation, such as fluid injection
into a formation, etc. The well performance analyzer 260 may
determine the new settings of the various devices in the system 10
that will mitigate or eliminate the potential negative effects of
the cross flow. The desired settings may include new settings for
chokes, valves, ESP, chemical injection, etc. These settings may be
chosen based on any selected criteria, including an economic
analysis, such as a net present value, optimizing or maximizing
production until a remedial work is performed.
[0037] Once the central controller 150 using the well performance
analyzer and/or other programs and algorithms detects an actual or
potential cross flow condition it sends messages, alarms and
reports 262 relating to the cross flow condition and the well
operations. Such information may include specific actions for the
operator to take, the actions that are automatically taken by the
controller 150, net present analysis information, plots relating to
the cross flow condition, new settings of the various devices, etc.
as shown at 260. These messages may be displayed at a suitable
display located at one or more locations, including at the well
site and/or at a remote control unit 185. The information may be
transmitted by any suitable data link, including an Ethernet
connection and the Internet 272 and may be any form, such as text,
plots, simulated picture, email, etc. The information sent by the
central controller may be displayed at any suitable medium, such as
a monitor. The remote locations may include client locations or
personnel managing the well from a remote office. The central
controller 150 utilizing data, such as current choke positions, ESP
frequency, downhole choke and valve positions, chemical, injection
unit operation and any other information 226 may determine one or
more adjustments to be made or actions to be taken relating to the
operation of the well, which operations when implemented are
expected to mitigate or eliminate certain negative effects of the
actual or potential cross flow condition on the well 50.
[0038] The well performance analyzer, in one aspect, may use a
forward looking model, which may use a nodal analysis, neural
network or another algorithm to estimate or assess the effects of
the suggested actions and to perform an economic analysis, such as
a net present value analysis based on the estimated effectiveness
of the actions. The well performance analyzer also may estimate the
cost of initiating any one or more of the actions and may perform a
comparative analysis of different or alternative actions. The well
performance analyzer also may use an iterative process to arrive at
an optimal set of actions to be taken by the operator and/or the
controller 150. The central controller may continually monitor the
well performance and the effects of the actions 264 and sends the
results to the operator and the remote locations. The central
controller may update the models, expected flow rates from the well
based on the new settings as shown at 234.
[0039] In one aspect, the central controller 150 may be configured
to wait for a period of time for the operator to take the suggested
actions (manual adjustments 265) and in response to the adjustments
made by the operator determine the effects of such changes on the
cross flow situation and the performance of the well. The
controller may send additional messages when the operator fails to
take an action and may initiate actions.
[0040] In another aspect, the central controller 150 may be
configured to automatically initiate one or more of the recommended
actions, for example, by sending command signals to the selected
device controllers, such as to ESP controller 242 to adjust the
operation of the ESP 30; control units or actuators (160, FIG. 1A
and element 240) that control downhole chokes 244, downhole valves
246; surface chokes 249, chemical injection control unit 250; other
devices 254, etc. Such actions may be taken in real time or near
real time. The central controller 150 continues to monitor the
effects of the actions taken 264. In another aspect, the central
controller 150 or the remote controller 185 may be configured to
update one or more models/algorithms/programs 234 for further use
in the monitoring of the well. Thus, the system 200 may operate in
a closed-loop form to continually monitor the performance of the
well, detect and/or predict cross flow conditions, determine
actions that will mitigate negative effects of cross flow,
determine the effects of any action taken by the operator, perform
economic analysis so as to enhance or optimize production from one
or more production zones.
[0041] The central controller 150 may be configured or programmed
to effect the recommended actions directly or through other control
units, such as the ESP control unit 130 and the additive injection
controller 80. In another aspect, the controller may perform a
nodal analysis to determine the desired changes or actions and
proceed to effect the changes as described above. In another
aspect, the central processor may transmit information to a remote
controller 185 via a suitable link, such a hard link, wireless link
or the Internet, and receive instructions from the remote
controller 185 relating to the recommended actions. In another
aspect, the central controller or the remote controller may perform
a simulation based on the recommended action to determine the
effect such actions will have on the operations of the wellbore. If
the simulation shows that the effects fail to meet certain preset
criterion or criteria, the processor performs additional analysis
to determine a new set of actions that will meet the set criterion
or criteria. It should be understood that separate controllers,
such as controllers 80, 130 and 150 are shown merely for ease of
explaining the methods and concepts described herein. In
embodiments, a single local controller, such as controller 150 or a
remote controller, such as controller 185, or a combination of any
such controllers may be utilized to cooperatively control the
various aspects of the system 10. Additionally, the central
controller 150 may update the database management system 199 based
on the operating conditions of the wellbore, which information may
be used to update the models used by the controller 150 for further
monitoring and management of the wellbore 50. The communication via
the Ethernet or the Internet enables two-way communication among
the operator and personnel at remote locations and allows such
personnel log into the database and monitor and control the
operation of the well 50. Also, it should be understood that the
present description refers to a well with two production zones
merely for ease of explanation. In aspects, embodiments can be
utilized in connection with two or more wellbores, each of which
may intersect the same production zones or different production
zones. Thus, while cross flow between two or more production zones
intersected by the same wellbore have been discussed, it should be
appreciated that system, methods and concepts described herein may
be used to determine undesirable flow conditions between any number
of production zones that are drained by the same or different
wells. Additionally, it should be appreciated that a cross flow is
only an illustrative of flow condition that can impact production
efficiency. In aspects, embodiment can be configured to evaluate
data from wellbore sensors to determine whether the data or data
trends indicate the occurrence of any preset or predetermined flow
condition.
[0042] As discussed herein, the disclosure, in one aspect, provides
method for managing fluid production from a wellbore having at
least two production zones that includes taking at least one first
measurement indicative of a selected parameter of a first
production zone, taking at least one second measurement indicative
of the selected parameter of a second production zone, and
determining occurrence of a cross flow condition from a trend
relating to at least one of the first measurement and the second
measurement. The selected parameter may: (i) pressure; (ii)
temperature; or (iii) fluid flow rate. The method may use nodal
analysis to predict the occurrence of the cross flow condition. The
method may further take the first measurement and the second
measurement over a time period and determine therefrom a rate of
change of one of the first measurement and the second measurement;
and determine the occurrence of the cross flow condition based at
least in part on the determined rate of change of at least one of
the first measurement and the second measurement. In the method,
alarm conditions may be sent upon the determination of the
occurrence of the cross flow condition. The method, in one aspect,
determines changes that may be made to the operation of one or more
devices, which when made may reduce or eliminates the cross flow
condition. In one aspect, certain devices relating to the wellbore
are automatically are set to new values. The changes can include
actions such as (i) closing a choke; (ii) changing frequency of an
electrical submersible pump pumping fluid; (iii) changing supply
amount of an additive to the wellbore; (v) closing a zone; (vi)
isolating a zone; (vi) decreasing surface pressure; and (vii)
opening a surface choke.
[0043] The disclosure also provides an apparatus that includes a
processor that receives an input relating to a first measurement of
a selected parameter corresponding to a first production zone and a
second measurement of the selected parameter relating to the second
production zone, each of the production zones producing a formation
fluid into a wellbore, wherein the processor determines an
occurrence of a cross flow condition in the wellbore from a trend
relating to at least one of the first measurement and the second
measurement. The selected parameters may be chosen from a group
consisting of: (i) pressure; (ii) temperature; and (iii) fluid flow
rate. The processor in one aspect may use a model and performs a
nodal analysis to determine the occurrence of the cross flow
condition. The measurements may be made continuously or
periodically over time. In one aspect, the processor determines a
rate of change of at least the first measurement and the second
measurement and determines the occurrence of the cross flow
condition based at least in part on the determined rate of change.
In one aspect, the processor may send one or more alarm conditions
that also may be displayed on a display for use by an operator and
such conditions may be sent to a remote location via any suitable
communication link, including the Internet. The processor also may
be configured to suggest adjustments to one or more operating
parameters of the wellbore to limit or eliminate the negative
impact of an anticipated or actual cross flow condition, which may
include, but not are limited to (i) operating a choke; (ii)
changing frequency of an electrical submersible pump pumping fluid;
(iii) operating a sliding sleeve valve; (iv) changing a supply of
the amount of an additive to the wellbore; (v) closing of a zone;
(vi) isolating a zone; (vi) decreasing the surface pressure; and
(vii) opening a surface choke. One or more computer models and
computer programs are stored in a computer-readable media that is
accessible to the processor and the processor executes the
instructions contained in the programs to perform the functions and
methods described herein. In one aspect, the programs include a
model that enables the controller to perform nodal analysis to
predict the occurrence of the cross flow and to simulate the
wellbore conditions based on the suggested changes and other inputs
relating to the settings of the various devices in the system.
[0044] While the foregoing disclosure is directed to certain
specific exemplary embodiments, various modifications will be
apparent to those skilled in the art. It is intended that all
modifications within the scope of the appended claims be embraced
by the foregoing disclosure.
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