U.S. patent application number 09/923059 was filed with the patent office on 2002-06-06 for monitoring of downhole parameters and tools utilizing fiber optics.
Invention is credited to Bidigare, Brian, Harrell, John, Johnson, Michael, Tubel, Paulo, Voll, Benn.
Application Number | 20020066309 09/923059 |
Document ID | / |
Family ID | 27556487 |
Filed Date | 2002-06-06 |
United States Patent
Application |
20020066309 |
Kind Code |
A1 |
Tubel, Paulo ; et
al. |
June 6, 2002 |
Monitoring of downhole parameters and tools utilizing fiber
optics
Abstract
The present invention provides systems utilizing fiber optics
for monitoring downhole parameters and the operation and conditions
of downhole tools. In one system fiber optics sensors are placed in
the wellbore to make distributed measurements for determining the
fluid parameters including temperature, pressure, fluid flow, fluid
constituents and chemical properties. Optical spectrometric sensors
are employed for monitoring chemical properties in the wellbore and
at the surface for chemical injection systems. Fiber optic sensors
are utilized to determine formation properties including
resistivity and acoustic properties compensated for temperature
effects. Fiber optic sensors are used to monitor the operation and
condition of downhole devices including electrical submersible
pumps and flow control devices. In one embodiment, a common fluid
line is used to monitor downhole parameters and to operate
hydraulically-operated devices. Fiber optic sensors are also
deployed to monitor the physical condition of power lines supplying
high electric power to downhole equipment. A light cell disposed
downhole is used to generate electric power in the wellbore, which
is used to charge batteries.
Inventors: |
Tubel, Paulo; (The
Woodlands, TX) ; Bidigare, Brian; (Kingwood, TX)
; Johnson, Michael; (Flower Mound, TX) ; Harrell,
John; (Waxahachie, TX) ; Voll, Benn; (Houston,
TX) |
Correspondence
Address: |
PAUL S MADAN
MADAN, MOSSMAN & SRIRAM, PC
2603 AUGUSTA, SUITE 700
HOUSTON
TX
77057-1130
US
|
Family ID: |
27556487 |
Appl. No.: |
09/923059 |
Filed: |
August 6, 2001 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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09923059 |
Aug 6, 2001 |
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09872591 |
Jun 1, 2001 |
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09872591 |
Jun 1, 2001 |
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09070953 |
May 1, 1998 |
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60045354 |
May 2, 1997 |
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60048989 |
Jun 9, 1997 |
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60052042 |
Jul 9, 1997 |
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60062953 |
Oct 10, 1997 |
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60073425 |
Feb 2, 1998 |
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60079446 |
Mar 26, 1998 |
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Current U.S.
Class: |
73/152.54 |
Current CPC
Class: |
E21B 23/03 20130101;
G01V 8/02 20130101; G01V 11/002 20130101; E21B 43/26 20130101; G01V
11/00 20130101; G01D 5/268 20130101; E21B 47/135 20200501; E21B
47/06 20130101; G01V 1/46 20130101; E21B 43/16 20130101; E21B
33/1275 20130101; E21B 47/017 20200501; E21B 47/10 20130101; E21B
41/02 20130101; E21B 47/07 20200501; E21B 49/00 20130101; G01V 7/08
20130101; E21B 43/123 20130101; E21B 47/107 20200501; G01V 1/52
20130101; E21B 47/113 20200501; E21B 49/08 20130101; G01N 21/31
20130101; G01V 2210/6163 20130101; E21B 43/122 20130101; G01V 1/42
20130101; E21B 41/0035 20130101; E21B 47/00 20130101; E21B 49/006
20130101; G01V 7/16 20130101; E21B 43/12 20130101; E21B 43/20
20130101; G01V 2210/6167 20130101; E21B 43/25 20130101; E21B 37/06
20130101; E21B 47/11 20200501; E21B 49/008 20130101; G01V 1/40
20130101 |
Class at
Publication: |
73/152.54 |
International
Class: |
E21B 047/00 |
Claims
What is claimed is:
1. A system for monitoring a downhole production fluid parameter,
comprising: (a) an optical spectrometer in a wellbore, said optical
spectrometer making measurements for the production parameter in
response to the supply of optical energy to the spectrometer; and
(b) a source of optical energy providing the optical energy to the
optical spectrometer.
2. The tool of claim 1 wherein the spectrometer provides signals
responsive to a downhole parameter which is one of (a) presence of
gas in a fluid, (b) presence of water in a fluid, (c) amount of
solids in fluid, (d) density of a fluid, (e) constituents of a
downhole fluid, and (f) chemical composition of a fluid.
3. The system of claim 1 wherein the optical spectrometer is
permanently deployed in the wellbore.
4. The system of claim 1 wherein the source of optical energy is
located in the wellbore.
5. The system of claim 1 wherein the optical spectrometer is
located in a drill string and makes the measurements during
drilling of the wellbore.
6. The system of claim 1 further comprising a processor determining
the downhole parameter utilizing the measurements from the optical
spectrometer.
7. The system of claim 6 wherein the processor processes data at
least in part downhole.
8. A system for determining an acoustic property of a subsurface
formation, comprising: (a) an acoustic fiber optic sensor in a
wellbore providing measurements of an acoustic property of the
formation surrounding the wellbore; (b) a fiber optic temperature
sensor in the wellbore for determining the temperature of the
formation; and (c) a processor determining from the acoustic sensor
measurements the acoustic property of the formation that is
compensated for temperature effects utilizing the temperature
sensor measurements.
9. The system of claim 8 wherein the acoustic property is one of
(a) acoustic velocity of the formation, and (b) travel time of an
acoustic wavefront in the formation.
10. The system of claim 8 wherein the processor processes the
measurements at least in part downhole.
11. The system of claim 8 wherein the acoustic sensor is one of (a)
permanently installed in the wellbore and (b) carried by a
measurement-while drilling tool taking said measurements during
drilling of the wellbore.
12. A system for determining resistivity of a subsurface formation,
comprising: (a) a fiber optic sensor in a wellbore providing
measurements for resistivity of the formation surrounding the
wellbore; and (b) a processor determining from the fiber optic
sensor measurements the resistivity of the formation surrounding
the wellbore.
13. The system of claim 12 wherein the fiber optic sensor is
disposed in one of (a) on a measurement while-drilling tool taking
said measurements during drilling of the wellbore and (b)
permanently installed in the wellbore.
14. The system of claim 12 wherein the processor processes the
measurements at least in part downhole.
15. A system for determining a formation parameter of a subsurface
formation, comprising: (a) a fiber optic sensor in a wellbore
providing measurements for determining a parameter selected from a
group consisting of electric field, radiation and magnetic field;
and (b) a processor determining from the fiber optic sensor
measurements the selected parameter.
16. The system of claim 15 wherein the fiber optic sensor is one of
(a) permanently installed in the wellbore and (b) carried by a
measurement-while drilling tool taking said measurements during
drilling of the wellbore.
17. A downhole tool monitoring system, comprising: (a) a tool in
the wellbore; and (b) a fiber optic sensor in a wellbore providing
measurements for an operating parameter of the tool.
18. The system of claim 17 wherein the operating parameter is one
of (a) vibration, (b) noise (c) strain (d) stress (e) displacement
(f) flow rate (g) mechanical integrity (h) corrosion (i) erosion
(j) scale (k) paraffin (l) hydrate, (m) displacement, (n)
temperature, (o) pressure, (p) acceleration, and (q) stress.
19. The system of claim 1 wherein the fiber optic sensor is one of
(a) vibration sensor (b) strain sensor (c) chemical sensor (e)
optical spectrometer sensor and (f) flow rate sensor, (g)
temperature sensor, and (h) pressure sensor.
20. The system of claim 17 wherein the downhole tool is one of a
flow control device, packer, sliding sleeve, screen, mud motor,
drill bit, bottom hole assembly, coiled tubing and casing.
21. A method of monitoring chemical injection into a surface
treatment system of an oilfield well, comprising: (a) injecting one
or more chemicals into the treatment system for the treatment of
fluids produced in the oilfield well; and (b) sensing at least one
chemical property of the fluid in the treatment system using at
least one fiber optic chemical sensor associated with the treatment
system.
22. The method of claim 21 wherein the fiber optic chemical sensor
is one of (a) a probe that includes a sol gel and (b) an optical
spectrometer that provides refracted light indicative of the
chemical property of the fluid.
23. A measurement-while drilling ("MWD") tool for use in drilling
of a wellbore, comprising: (a) at least one fiber optic sensor
carried by the tool providing measurements responsive to one or
more downhole parameters of interest during drilling of the
wellbore; (b) a light source in the tool providing light energy to
the at least one fiber optic sensor for taking sid measurements;
and (c) a processor determining from said measurements the one or
more parameters of interest at least in part downhole.
24 The tool of claim 23 wherein the at least one fiber optic sensor
includes at least one of (a) a fluid flow rate sensor, (b) a
vibration sensor, (d) a spectrometer, (e) sensor that determines a
chemical property of the fluid, (f) a density measuring sensor, (g)
resistivity measuring sensor, (h) a plurality of distributed
pressure sensors, (i) a temperature sensor, (j) a pressure sensor,
(k) a strain gauge, (l) a hydrophone, (m) a plurality of
distributed pressure sensors, (n) a plurality of distributed
temperature sensors, (o)an accelerometer, and (p) an acoustic
sensor.
25. The tool of claim 23 wherein the one or more parameters of
interest include at least one of (a) fluid flow rate, (b) flow of
fluid through the tool, (c) vibration, (d) composition of wellbore
fluid, (e) constituents of fluid in the wellbore, (f) constituents
of the formation fluid, (g) water content in the formation fluid,
(h) presence of gas in the formation fluid (i) fluid density (j) a
physical condition of the tool (k) a formation evaluation property,
(l) resistivity, (m) temperature gradient, and (n) pressure
gradient.
26. The tool of claim 23 wherein the at least one fiber optic
sensor includes a set of fiber optic sensors spaced along a fiber
optic string.
27. The tool of claim 26 wherein at last some of the sensors are
configured to provide measurements for more than one downhole
parameters.
28. The tool of claim 23 wherein the at least one fiber optic
sensor includes a set of sensors and the processor multiplexes
between such sensors according to programmed instructions provided
to the processor to obtain measurements of the desired parameters
of interest.
29. The tool of claim 23 further comprising a mud motor, said mud
motor having a rotor rotating in an elastomeric stator upon the
supply of a fluid under pressure to the mud motor.
30. The tool of claim 29 wherein the at least one fiber optic
sensor includes a plurality of fiber otic temperature sensors in
the mud motor for measuring the temperature of the elastomeric
stator, thereby providing an operating condition of the stator.
31. The tool of claim 30 wherein the processor provides signals for
adjusting supply of the fluid under pressure to the mud motor so as
to maintain the temperature of the stator at a desired value.
32. A method of monitoring and controlling an injection operation,
comprising: (a) locating in a production well a plurality of
distributed fiber optic sensors; (b) injecting a fluid in an
injection well formed spaced apart from the production wellbore;
(b) determining from the fiber optic sensor measurements a
parameter of the formation between the production well and the
injection well; and (c) controlling the injection of the fluid in
response to the determined parameter.
33. A downhole injection evaluation system comprising: (a) at least
one sensor permanently disposed in an injection well for sensing at
least one parameter associated with injecting of a fluid into a
formation.
34. A downhole injection evaluation system as claimed in claim 33
wherein said system further includes an electronic controller
operably connected to said at least one downhole sensor.
35. A downhole injection evaluation system as claimed in claim 34
wherein said at least one downhole sensor is operably connected to
at least one production well sensor to provide said electronic
controller, operably connected to said at least one downhole sensor
and to said at least one production well sensor, with information
from both sides of a fluid front moving between said injection well
and said production well.
36. A system for optimizing hydrocarbon production comprising: (a)
a production well; (b) an injection well, said production well and
said injection well being data transmittably connected; and (c) at
least one sensor located in either of said injection well and said
production well, said at least one sensor being capable of sensing
at least one parameter associated with an injection operation, said
sensor being operably connected to a controller for controlling
injection in the injection well.
37. A method for avoiding injection induced unintentional fracture
growth comprising: (a) providing at least one acoustic sensor in an
injection well; (b) monitoring said at least one sensor; and (c)
varying pressure of a fluid being injected to avoid a predetermined
threshold level of acoustic activity received by said at least one
sensor.
38. A method for enhancing hydrocarbon production wherein at least
one injection well and an associated production well include at
least one sensor and at least one flow controller comprising
providing a system capable of monitoring said at least one sensor
in each of said wells and controlling said at least one flow
controller in each of said wells in response thereto to optimize
hydrocarbon production.
39. A method of making measurements in a wellbore, comprising: (a)
locating at least one fiber-optic sensor in the wellbore, said
sensor providing measurements responsive to one or more downhole
parameters; (b) locating a light source in the wellbore, said light
source providing light energy to the at least one fiber optic
sensor for making the measurements; and (c) processing the fiber
optic sensor measurements and computing therefrom the one or more
downhole parameters.
40. The method according to claim 39, wherein the downhole
parameters include at least one of (a) fluid flow rate, (b) flow of
fluid through the tool, (c) vibration, (d) composition of wellbore
fluid, (e) constituents of fluid in the wellbore, (f) constituents
of the formation fluid, (g) water content in the formation fluid,
(h) presence of gas in the formation fluid (i) fluid density (j) a
physical condition of the tool (k) a formation evaluation property,
(l) resistivity, (m) temperature gradient, (n) pressure gradient,
and (o) seismic response of induced acoustic energy.
41. A method of avoiding drilling into preexisting wellbore,
comprising: drilling a wellbore with a drilling assembly carrying a
drill bit wherein the drill bit induces acoustic energy into
subsurface formations; providing at least one fiber optic acoustic
sensor in the preexisting wellbore for detecting acoustic energy
generated by the drill bit; determining from the detected signals
location of the drill bit relative to the preexisting wellbore; and
drilling the wellbore a desired distance from the preexisting
wellbore thereby avoiding drilling the wellbore into the
preexisting wellbore.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from Provisional U.S.
patent application Ser. No. 60/045,354 filed on May 2, 1997; Ser.
No. 60/048,989 filed on Jun. 9, 1997; Ser. No. 60/052,042 filed on
Jul. 9, 1997; Ser. No. 60/062,953 filed on Oct. 10, 1997; Ser. No.
67/073,425 filed on Feb. 2, 1998; and Ser. No. 60/079,446 filed on
Mar. 26, 1998. Reference is also made to a United States Patent
Application filed on the same date as the present application under
Attorney Docket No. 414-12049 US, the contents of which are
incorporated here by reference.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] This invention relates generally to oilfield operations and
more particularly to systems and methods utilizing fiber optics for
monitoring wellbore parameters, formation parameters, drilling
operations, condition of downhole tools installed in the wellbores
or used for drilling such wellbores, for monitoring reservoirs and
for monitoring of remedial work.
[0004] 2. Background of the Art
[0005] A variety of techniques have been utilized for monitoring
reservoir conditions, estimation and quantities of hydrocarbons
(oil and gas) in earth formations, for determination formation and
wellbore parameters and form determining the operating or physical
condition of downhole tools.
[0006] Reservoir monitoring typically involves determining certain
downhole parameters in producing wellbores, such as temperature and
pressure placed at various locations in the producing wellbore,
frequently over extended time periods. Wireline tools are most
commonly utilized to obtain such measurements, which involves
shutting down the production for extended time periods to determine
pressure and temperature gradients over time.
[0007] Seismic methods wherein a plurality of sensors are placed on
the earth's surface and a source placed at the surface or downhole
are utilized to obtain seismic data which is then used to update
prior three dimensional (3-D") seismic maps. Three dimensional maps
updated over time are sometimes referred to as "4-D" seismic maps.
The 4-D maps provide useful information about reservoirs and
subsurface structure. These seismic methods are very expensive. The
wireline methods are utilized at great time intervals, thereby not
providing continuous information about the wellbore conditions or
that of the surrounding formations.
[0008] Permanent sensors, such as temperature sensors, pressure
sensors, accelerometers or hydrophones have been placed in the
wellbores to obtain continuous information for monitoring wellbores
and the reservoir. Typically, a separate sensor is utilized for
each type of parameter to be determined. To obtain such
measurements from useful segments of each wellbore, which may
contain multilateral wellbores, requires using a large number of
sensors, which require a large amount of power, data acquisition
equipment and relatively large amount of space, which in many cases
is impractical or cost prohibitive.
[0009] In production wells, chemicals are often injected downhole
to treat the producing fluids. However, it can be difficult to
monitor and control such chemical injection in real time.
Similarly, chemicals are typically used at the surface to treat the
produced hydrocarbons (i.e. break down emulsions) and to inhibit
corrosion. However, it can be difficult to monitor and control such
treatment in real time.
[0010] Formation parameters are most commonly measured by
measurement-while-drilling tools during the drilling of the
wellbores and by wireline methods after the wellbores have been
drilled. The conventional formation evaluation sensors are complex
and large in size and thus require large tools. Additionally such
sensors are very expensive.
[0011] Prior art is also very deficient in providing suitable
system and methods for monitoring the condition or health of
downhole tools. Tool conditions should be monitored during the
drilling process, as the tools are deployed in the wellbore and
after deployment, whether during the completion phase or the
production phase.
[0012] The present invention addresses some of the above-described
prior deficiencies and provides systems and methods which utilize a
variety of fiber optic sensors for monitoring wellbore parameters,
formation parameters, drilling operations, condition of downhole
tools installed in the wellbores or used for drilling such
wellbores, for monitoring reservoirs and for monitoring of remedial
work. In some applications, the same sensor is configured to
provide more than one measurement. In many instances these sensors
are relatively, consume less power and can operate at higher
temperatures than the conventional sensors.
SUMMARY OF THE INVENTION
[0013] The present invention provides fiber optics based systems
and methods for monitoring downhole parameters and the condition
and operation of downhole tools. The sensors may be permanently
disposed downhole. The light source for the fiber optic sensors may
be disposed in the wellbore or at the surface. The measurements
from such sensors may be processed downhole and/or at the surface.
Data may also be stored for use for processing. Certain sensors may
be configured to provide multiple measurements. The measurements
made by the fiber optic sensors in the present invention include
temperature, pressure, flow, liquid level, displacement, vibration,
rotation, acceleration, acoustic velocity, chemical species,
acoustic field, electric field, radiation, pH, humidity, electrical
field, magnetic field, corrosion and density.
[0014] In one system, a plurality of spaced apart fiber optic
sensors are disposed in the wellbore to take the desired
measurements. The light source and the processor may be disposed in
the wellbore or at the surface. Two way communication between the
sensors and the processor is provided via fiber optic links or by
conventional methods. A single light source may be utilized in the
multilateral wellbore configurations. The sensors may be
permanently installed in the wellbores during the completion or
production phases. The sensors preferably provide measurements of
temperature, pressure and flow for monitoring the wellbore
production and for performing reservoir analysis.
[0015] In another system the fiber optic sensors are deployed in a
production wellbore to monitor the injection operations, fracturing
and faults. Such sensors may also be utilized in the injection
well. Controllers are provided to control the injection operation
in response to the in-situ or real time measurements.
[0016] In another system, the fiber optic sensors are used to
determine acoustic properties of the formations including acoustic
velocity and travel time. These parameters are preferably
compensated for the effects of temperature utilizing the downhole
temperature sensor measurements. Acoustic measurements are use for
cross-well tomography and for updating preexisting seismic data or
maps.
[0017] The distributed sensors of this invention find particular
utility in the monitoring and control of various chemicals which
are injected into the well. Such chemicals are injected downhole to
address a large number of known problems such as for scale
inhibition and for the pretreatment of the fluid being produced. In
accordance with the present invention, a chemical injection
monitoring and control system includes the placement of one or more
sensors downhole in the producing zone for measuring the chemical
properties of the produced fluid as well as for measuring other
downhole parameters of interest. These sensors are preferably fiber
optic based and are formed from a sol gel matrix and provide a high
temperature, reliable and relatively inexpensive indicator of the
desired chemical parameter. The downhole chemical sensors may be
associated with a network of distributed fiber optic sensors
positioned along the wellbore for measuring pressure, temperature
and/or flow. Surface and/or downhole controllers receive input from
the several downhole sensors, and in response thereto, control the
injection of chemicals into the brothel.
[0018] The chemical parameters are preferably measured in real time
and on-line and then used to control the amount and timing of the
injection of the chemicals into the wellbore or for controlling a
surface chemical treatment system.
[0019] An optical spectrometer may be used downhole to determine
the properties of downhole fluid. The spectrometer includes a
quartz probe in contact with the fluid. Optical energy provided to
the probe, preferably from a downhole source. The fluid properties
such as the density, amount of oil, water, gas and solid contents
affect the refraction of the light. The refracted light is analyzed
to determine the fluid properties. The spectrometer may be
permanently installed downhole.
[0020] The fiber optic sensors are also utilized to measure
formation properties, including resistivity, formation acoustic
velocity. Other measurements may include electric field, radiation
and magnetic field. Such measurements may be made with sensors
installed or placed in the wellbore for monitoring the desired
formation parameters. Such sensors are also placed in the drill
string, particularly in the bottom hole assembly to provide the
desired measurements during the drilling of the wellbore.
[0021] In another system, the fiber optic sensors are used to
monitor the health or physical condition and/or the operation of
the downhole tools. The measurements made to monitor the tools
include one or more of (a) vibration, (b) noise (c) strain (d)
stress (e) displacement (f) flow rate (g) mechanical integrity (h)
corrosion (i) erosion (j) scale (k) paraffin and (l) hydrate.
[0022] Examples of the more important features of the invention
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 maybe appreciated. There
are, of course, additional features of the invention that will be
described hereinafter and which will form the subject of the claims
appended hereto.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] For a detailed understanding of the present invention,
reference should be made to the following detailed description of
the preferred embodiments, taken in conjunction with the
accompanying drawings, in which like elements have been given like
numerals, wherein:
[0024] FIG. 1 shows a schematic illustration of a multilateral
wellbore system and placement of fiber optic sensors according to
one embodiment of the present invention.
[0025] FIG. 2 shows a schematic illustration of a configurations of
wellbores using fiber-optic sensor arrangements according to the
present invention to: (a) to detect and monitor compressive
stresses exerted on wellbore casings and formations; (b) determine
the effectiveness of the injection process and in-situ control of
the injection operations, and (c) make acoustic measurements for
cross-well tomography and to generate and/or update subsurface
seismic maps.
[0026] FIG. 3 is a schematic illustrating both an injection well
and a production well having sensors and flood front running
between the wells and loss through unintended fracturing.
[0027] FIG. 4 is a schematic representation wherein the production
wells are located on either side of the injection well.
[0028] FIG. 5 is a schematic illustration of a chemical injection
monitoring and control system utilizing a distributed sensor
arrangement and downhole chemical monitoring sensor system in
accordance with one embodiment of the present invention;
[0029] FIG. 6 is a schematic illustration of a fiber optic sensor
system for monitoring chemical properties of produced fluids;
[0030] FIG. 7 is a schematic illustration of a fiber optic sol gel
indicator probe for use with the sensor system of FIG. 6;
[0031] FIG. 8 is a schematic illustration of a surface treatment
system in accordance with the present invention; and
[0032] FIG. 9 is a schematic of a control and monitoring system for
the surface treatment system of FIG. 8.
[0033] FIG. 10 is a schematic illustration of a wellbore system
wherein a fluid conduit along a string placed in the wellbore is
utilized for activating a hydraulically-operated device and for
monitoring downhole parameters using fiber optic sensors along its
length.
[0034] FIG. 11 shows a schematic diagram of a producing well
wherein a fiber optic cable with sensors is utilized to determine
the condition or health of downhole devices and to make
measurements downhole relating to such devices and other downhole
parameters.
[0035] FIG. 12 is a schematic illustration of a wellbore system
wherein electric power is generated downhole utilizing a light cell
for use in operating sensors and devices downhole.
[0036] FIG. 13 is a schematic illustration of a wellbore system
wherein a permanently installed electrically-operated device is
monitored and operated by a fiber optic based system.
[0037] FIGS. 14A and 14B show a method to avoid drilling wellbores
too close to or into each other from a common platform utilizing
Fiber optic sensor in the drilling string.
[0038] FIG. 14C is schematic illustration of a bottomhole assembly
for use in drilling wellbores that utilizes with a number of
fiber-optic sensors for measuring various downhole parameters
during drilling of the wellbores.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0039] FIG. 1 shows an exemplary main or primary wellbore 12 formed
from the surface 14 and lateral wellbores 16 and 18 formed from the
main wellbore 18. For the purpose of explanation, and not as any
limitation, the main wellbore 12 is partly formed in a producing
formation or pay zone I and partly in a non-producing formation or
dry formation II. The lateral wellbore 16 extends from the main
wellbore 12 at a juncture 24 into a second producing formation III.
For the purposes of illustration, the wellbores herein are shown
drilled from land, however, this invention is equally applicable to
offshore wellbores. It should be noted that all wellbore
configurations shown and described herein are to illustrate the
concepts of present invention and shall not be construed to limit
the inventions claimed herein.
[0040] In one application, a number of fiber optic sensors 40 are
place in the wellbore 12. A single or a plurality of fiber optic
sensors 40 may be used so as to install the desired number of fiber
optic sensors 40 in the wellbore 12. As an example, FIG. 1 shows
two serially coupled fiber optic segments 41a and 41b, each
containing a plurality of spaced apart fiber optic sensors 40. A
light source and detector (LS) 46a coupled to an end 49 of the
segment 41a is disposed in the wellbore 12 to transmit light energy
to the sensors 40 and to receive the reflected light energy from
the sensors 40. A data acquisition and processing unit (TDA) 48a
(also referred to herein as a "processor" or "controller") may be
disposed downhole to control the operation of the sensors 40, to
process downhole sensor signals and data, and to communicate with
other equipment and devices, including devices in the wellbores or
at the surface (not shown).
[0041] Alternatively, a light source 46b and/or the data
acquisition and processing unit 48b may be place at the surface 14.
Similarly, fiber optic sensor strings 45 may be disposed in other
wellbores in the system, such as wellbores 16 and wellbore 18. A
single light source, such as the light source 46a or 46b may be
utilized for all fiber optic sensors in the various wellbores, such
as shown by dotted line 70. Alternatively, multiple light sources
and data acquisition units may be used downhole, at the surface or
in combination. Since the same sensor may make different types of
measurements, the data acquisition unit 48a or 48 is programmed to
multiplex the measurement. Also different types of sensors may be
multiplexed as required. Multiplexing techniques are know in the
art and are thus not described in detail herein. The data
acquisition unit 46a may be programmed to control the downhole
sensors 40 autonomously or upon receiving command signals from the
surface or a combination of these methods.
[0042] The sensors 40 may be installed in the wellbores 12, 16, and
18 before or after installing casings in wellbores, such as casing
52 shown installed in the wellbore 12. This may be accomplished by
connecting the strings 41a and 41b along the inside of the casing
52. In one method, the strings 41a and 41b may be deployed or
installed by robotics devices (not shown). The robotics device
would move the sensor strings 41a and 41b within the wellbore 12 to
the desired location and install them according to programmed
instructions provided to the robotics device. The robotics device
may also be utilized to replace a sensor, conduct repairs retrieve
the sensors or strings to the surface and monitor the operation of
downhole sensors or devices and gather data. Alternatively, the
fiber optic sensors 40 maybe placed in the casing 52 (inside,
wrapped around, or in the casing wall) at the surface while
individual casing sections (which are typically about forty-foot
long) are joined prior to conveying the casing sections into the
borehole. Stabbing techniques for joining casing or tubing sections
are known in the art and are preferred over rotational joints
because stabbing generally provides better alignment of the end
couplings 42 and also because it allows operators to test and
inspect optical connections between segments for proper two-way
transmission of light energy through the entire string 41. For
coiled tubing applications, the sensors may be wrapped on the
outside or placed in conduit inside the tubing. Light sources and
data acquisition unit may also be placed in the coiled tubing prior
to or after deployment.
[0043] Thus, in the system described in FIG. 1, a plurality of
fiber optic sensors 40 are installed spaced apart in one or more
wellbores, such as wellbores 12, 16 and 18. If desired, each fiber
optic sensor 40 can be configured to operate in more than one mode
to provide a number of different measurements. The light source
46a, and data detection and acquisition system 48a may be placed
downhole or at the surface. Although each fiber optic sensor 40 may
provide measurements for multiple parameters, such sensors are
still relatively small compared to individual commonly used single
measurement sensors, such as pressure sensors, stain gauges,
temperature sensors, flow measurement devices and acoustic sensors.
This enables making a large number of different types of
measurements utilizing relatively small downhole space. Installing
data acquisition and processing devices or units 48a downhole
allows making a large number of data computations and processing
downhole, avoiding the need of transmitting large amounts of data
to the surface. Installing the light source 46a downhole allows
locating the source 46a close to the sensors 40, which avoids
transmitting light to great distances from the surface thus
avoiding loss of light energy. The data from the downhole
acquisition system 48a may be transmitted to the surface by any
suitable communication links or method including optical fibers,
wire connections, electromagnetic telemetry and acoustic methods.
Data and signals may be transmitted downhole using the same
communication links. Still in some applications, it may be
desirable to locate the light source 46b and/or the data
acquisition and processing system 48b at the surface. Also, in some
cases, it may be more advantageous to partially process data
downhole and partially at the surface.
[0044] In the present invention, the fiber optic sensors 40 may be
configured to provide measurements for temperature, pressure, flow,
liquid level displacement, vibration, rotation, acceleration,
velocity, chemical species, radiation, pH, humidity, electric
fields, acoustic fields and magnetic fields.
[0045] Still referring to FIG. 1, any number of conventional
sensors, generally denoted herein by numeral 60, may be disposed in
any of the wellbores 12, 16 and 18. Such sensors may include
sensors for determining resistivity of fluids and formations, gamma
rays sensors and hydrophones. The measurements from the fiber optic
sensors 40 and sensors 60 may be combined to determine the various
conditions downhole. For example flow measurements from fiber optic
sensors and the resistivity measurements from conventional sensors
may be combined to determine water saturation or to determine the
oil, gas an water content. Alternatively, the fiber optic sensors
may be utilized to determine the same parameters.
[0046] In one mode, the fiber optic sensors are permanently
installed in the wellbores at selected locations. In a producing
wellbore, the sensors continuously or periodically (as programmed)
provide the pressure and/or temperature and/or fluid flow
measurements. Such measurements are preferably made for each
producing zone in each of the wellbores. To perform certain types
of reservoir analysis, it is required to know the temperature and
pressure build rates in the wellbores. This requires measuring the
temperature and pressure at selected locations downhole over
extended time period after shutting down the well at the surface.
In the prior art methods, the well is shut down at the surface, a
wireline tool is conveyed in to the wellbore and positioned at one
location in the wellbore. The tool continuously measure temperature
and pressure and may provide other measurements, such as flow
control. These measurements are then utilized to perform reservoir
analysis, which may include determining the extent of the
hydrocarbon reserves remaining in a field, flow characteristics of
the fluid from the producing formations, water content, etc.
[0047] The above-described prior art methods do not provide
continuous measurements while the well is producing and requires
special wireline tools that must be conveyed downhole. The present
invention, on the other hand, provides in-situ measurements while
the wellbore is producing. The fluid flow information from each
zone is used to determine the effectiveness of each producing zone.
Decreasing flow rates over time may indicate problems with the flow
control devices, such as screens and sliding sleeves, or clogging
of the perforations and rock matrix near the wellbore. This
information is used to determine the course of action, which may
include further opening or closing sliding sleeves to increase or
decrease the production rate, remedial work, such as cleaning or
reaming operations, shutting down a particular zone, etc. The
temperature and pressure measurements are used to continually
monitor each production zone and to update reservoir models. To
make measurement for determining the temperature and pressure
buildup rates, the wellbores are shut down and making of
measurements continues. This does not require transporting wireline
tools to the location, which can be very expensive for offshore
wellbores and wellbores drilled in remote locations. Further, the
in-situ measurements and computed data can be communicated to a
central office or to the offices of log and reservoir engineers via
satellite. This continuous monitoring of wellbores allows taking
relatively quick action, which can significantly improve the
hydrocarbon production from the wellbores. The above described
measurements may also be taken for non-producing zones, such as
zone II, to aid in reservoir modeling, to determine the effect of
production from various wellbores on the field in which the
wellbores are drilled. Optical spectrometers, as described later
may be used to determine the constituents of the formation fluid
and certain chemical properties of such fluids. Presence of gas may
be detected to prevent blow-outs or to take other actions.
[0048] FIG. 2 shows a plurality of wellbores 102, 104 and 106
formed in a field 101 from the earth's surface 110. The wellbores
in FIG. 2 are configured to describe the use of the fiber-optic
sensor arrangements according to the present invention to: (a)
detect compressive stresses exerted into wellbore casings due to
depletion of hydrocarbons or other geological phenomena; (b)
determine the effectiveness of injection operations and for in-situ
monitoring and control of such operations, and (c) make acoustic
measurements for cross-well tomography and to generate and/or
update subsurface seismic maps.
[0049] As an example only, and not as any limitation, FIG. 2 shows
three wellbores 102, 104 and 106 formed in a common field or region
of interest 101. For the purpose of illustration, the wellbores
102, 104 and 106 are shown lined with respective casings 103, 105
and 107. Wellbore 102 contains a string 122 of fiber-optic sensors
40. The signals and data between the downhole sensor strings 122
and the surface 110 are communicated via a two-way telemetry link
126. The casing 103 may be made by coupling or joining tubulars or
casing sections at the surface prior to their insertion into the
wellbore 102. The casing joints are shown by numerals 120a-n, which
as indicated are typically about forty (40) feet apart. Coiled
tubing may also be used as the casing.
[0050] The wellbore 102 has a production zone 130 from which
hydrocarbons are produced via perforations 132 made in the casing
103. The production zone 130 depletes as the fluid flows from the
production zone 130 into the wellbore 102. If the production rate
is high, the rate of fluid depletion in the formations surrounding
the production zone 130 may be greater than the rate at which
fluids can migrate into the formation to fill the depleted pores.
The weight of the formation 138 above the production zone exerts
pressure 134 on the zone 130. If the pressure 134 is grater than
what the rock matrix of the zone 130 can support, it starts to
collapse, thereby exerting compressive stress on the casing 103. If
the compressive stress is excessive, the casing 103 may break at
one or more of the casing joints 102a-n. In case of the coiled
tubing, it may buckle or collapse due to stresses. The stresses can
also occur due to natural geological changes, such as shifting of
the subsurface strata or due to deletion by other wells in the
field 101.
[0051] To detect compressive stresses in the casing 103, the fiber
optic sensors 40 may be operated in the mode that provides strain
gauge type of measurements, which are then utilized to determine
the extent of the compressive stress on the casing 103. Since the
sensor string 122 spans several joints, the system can be used to
determine the location of the greatest stress in the casing 103 and
the stress distribution along any desired section of the casing
103. This information may be obtained periodically or continuously
during the life of the wellbore 102. Such monitoring of stresses
provides early warning about the casing health or physical
condition and the condition of the zone 130. This information
allows the operator of the wellbore 102 to either decrease the
production from the wellbore 102 or to shut down the well bore 102
and take remedial measures to correct the problem.
[0052] The use of the fiber optic sensors to determine the
effectiveness of remedial operations, such as fracturing or
injection, will be described while referring to wellbores 104 and
106 of FIG. 2. Wellbore 104 is shown located at a distance
"d.sub.1" from the wellbore 102 and the wellbore 106 at a distance
"d.sub.2" from the wellbore 104. A string 124 containing a number
of spaced apart fiber-optic sensors 40 is disposed in the wellbore
104. The length of the string 124 and the number of sensors 40 and
their spacing depends upon the specific application. The signals
and data between the string 124 and a surface equipment 151 are
communicated over a two-way telemetry or communications link
128.
[0053] For the purpose of illustration and not as any limitation,
the wellbore 106 will be utilized for injection purposes. The
wellbore 106 contains perforated zone 160. The wellbore is plugged
by a packer or any other suitable device 164 below the perforations
to prevent fluid flow beyond or downhole of the packer 164. To
perform an injection operation, such as for fracturing the
formation around the wellbore 106 or to stimulate the production
from other wellbores in the field 101, such as the wellbore 104, a
suitable fluid 166 (such as steam) migrates toward the wellbore 104
and may create a fluid wall 107a. This causes the pressure across
the wellbore 104 and fluid flow from the formation 180 into the
wellbore 104 may increase. Fracturing of the formation 180 into the
wellbore 104 may increase. Additionally, the fracturing of the
formation 180 generates seismic waves, which generate acoustic
energy. The fiber optic sensors 40 along with any other desired
sensors disposed in the wellbore 104 measure the changes in the
pressure, temperature, fluid flow, acoustic signals along the
wellbore 104. The sensor measurements (signals) are processed to
determine the effectiveness of the injection operations. For
example, the change in pressure, fluid flow at the wellbore 104 and
the time and amount of injected material can be used to determine
the effectiveness of the injection operations. Also, acoustic
signals received at the wellbore provide useful information about
the extent of fracturing of the rock matrix of formation 180. Also,
the acoustic signals received at the wellbore provide useful
information about the extent of fracturing of the rock matrix for
the formation 100. The acoustic signal analysis is used to
determine whether to increase or decrease the pressure of the
injected fluids 166 or to terminate the operation. This method
enables the operators to continuously monitor the effect of the
injection operation in one wellbore, such as the wellbore 106, upon
the other wellbores in the field, such as wellbore 104.
[0054] The sensor configuration shown in FIG. 2 may be utilized to
map subsurface formations. In one method, an acoustic source (AS)
170, such as a vibrator or an explosive charge, is activated at the
surface 110. The sensors 40 in the wellbores 102 and 104 detect
acoustic signals which travel from the source 170 to the sensors 40
through the formation 180. These signals are processed by any of
the methods known in the art to map the subsurface formations
and/or update the existing maps, which are typically obtained prior
to drilling wellbores, such as wellbores 102 and 104. Two
dimensional or three dimensional seismic maps are commonly obtained
before drilling wellbores. The data obtained by the above-described
method is used to update such maps. Updating three dimensional or
3D maps over time provides what are referred to in the oil and gas
industry as four dimensional or "4D" maps. These maps are then used
to determine the conditions of the reservoirs, to perform reservoir
modeling and to update existing reservoir models. These reservoir
models are used to manage the oil and gas production from the
various wellbores in the field. The acoustic data obtained above is
also utilized for cross-well tomography. Also, the acoustic source
170 may be disposed (activated) within one or more of the
wellbores, such as shown by numeral 170 in wellbore 104. The
acoustic source is moved to other locations, such as shown by
dotted box 170 to take additional measurements. The fiber optic
sensors described herein may be permanently deployed in the
wellbores.
[0055] In another embodiment of the invention relating to
fracturing, illustrated schematically in FIG. 3, downhole sensors
measure strain induced in the formation by the injected fluid.
Strain is an important parameter for avoiding exceeding the
formation parting pressure or fracture pressure of the formation
with the injected fluid. By avoiding the opening of or widening of
natural pre-existing fractures large unswept areas of the reservoir
can be avoided. The reason this information is important in the
regulation of pressure of the fluid to avoid such activity is that
when pressure opens fractures or new fractures are created there is
a path of much less resistance for the fluid to run through. Since
the injection fluid will follow along the path of least resistance
it would generally run in the fractures and around areas of the
reservoir that need to be swept. This substantially reduces its
efficiency. The situation is generally referred to in the art as an
"artificially high permeability channel." Another detriment to such
a condition is the uncontrolled loss of injected fluids. This
results in loss of oil due to the reduced efficiency of the sweep
and additionally may function as an economic drain due to the loss
of expensive fluids.
[0056] FIG. 3 schematically illustrates the embodiment and the
condition set forth above by illustrating an injection well 250 and
a production well 260. Fluid 252 is illustrated escaping via the
unintended fracture from the formation 254 into the overlying gas
cap level 256 and the underlying water table 261. The condition is
avoided by the invention by using pressure sensors to limit the
injection fluid pressure as described above. The rest of the fluid
252 is progressing as it is intended to through the formation 254.
In order to easily and reliably determine what the stress is in the
formation 54, fiber optic acoustic sensors 256 are located in the
injection well 250 at various points therein. The acoustic sensors
256 pick up sounds generated by stress in the formation which
propagate through the reservoir fluids or reservoir matrix to the
injection well. In general, higher sound levels would indicate
severe stress in the formation and should generate a reduction in
pressure of the injected fluid whether by automatic control or by
technician control. A data acquisition system 258 is preferable to
render the system extremely reliable and system 258 may be at the
surface where it is illustrated in the schematic drawing or may be
downhole. Based upon acoustic signals received the system of the
invention, preferably automatically, although manually is workable,
reduces pressure of the injected fluid by reducing pump pressure.
Maximum sweep efficiency is thus obtained.
[0057] In yet another embodiment of the invention, as schematically
illustrated in FIG. 4, acoustic generators and receivers are
employed to determine whether a formation which is bifurcated by a
fault is sealed along the fault or is permeable along the fault. It
is known by one of ordinary skill in the art that different strata
within a formation bifurcated by a fault may have some zones that
flow and some zones that are sealed; this is the illustration of
FIG. 4. Referring directly to FIG. 4, injection well 270 employs a
plurality of fiber optic sensors 272 and acoustic generators 274
which, most preferably, alternate with increasing depth in the
wellbore. In production well 280, a similar arrangement of sensors
272 and acoustic generators 274 are positioned. The sensors and
generators are preferably connected to processors which are either
downhole or on the surface and preferably also connect to the
associated production or injection well. The sensors 272 can
receive acoustic signals that are naturally generated in the
formation, generated by virtue of the fluid flowing through the
formation from the injection well and to the production well and
also can receive signals which are generated by signal generators
274. Where signal generators 274 generate signals, the reflected
signals that are received by sensors 272 over a period of time can
indicate the distance and acoustic volume through which the
acoustic signals have traveled. This is illustrated in area A of
FIG. 4 in that the fault line 275 is sealed between area A and area
B on the figure. This is illustrated for purposes of clarity only
by providing circles 276 along fault line 275. The areas of fault
line 275 which are permeable are indicated by hash marks 277
through fault line 275. Since the acoustic signal represented by
arrows and semi-curves and indicated by numeral 278 cannot
propagate through the area C which bifurcates area A from area B on
the left side of the drawing, that signal will bounce and it then
can be picked up by sensor 272. The time delay, number and
intensity of reflections and mathematical interpretation which is
common in the art provides an indication of the lack of pressure
transmissivity between those two zones. Additionally this pressure
transmissivity can be confirmed by the detection by said acoustic
signals by sensors 272 in the production well 280. In the drawing,
the area directly beneath area A, indicated as area E, is permeable
to area B through fault 275 because the region D in that area is
permeable and will allow flow of the flood front from the injection
well 270 through fault line 275 to the production well 280.
Acoustic sensors and generators can be employed here as well since
the acoustic signal will travel through the area D and, therefore,
reflection intensity to the receivers 272 will decrease. Time delay
will increase. Since the sensors and generators are connected to a
central processing unit and to one another it is a simple operation
to determine that the signal, in fact, traveled from one well to
the other and indicates permeability throughout a particular zone.
By processing the information that the acoustic generators and
sensors can provide the injection and production wells can run
automatically by determining where fluids can flow and thus opening
and closing valves at relevant locations on the injection well and
production well in order to flush production fluid in a direction
advantageous to run through a zone of permeability along the
fault.
[0058] Other information can also be generated by this alternate
system of the invention since the sensors 272 are clearly capable
of receiving not only the generated acoustic signals but naturally
occurring acoustic waveforms arising from both the flow of the
injected fluids as the injection well and from those arising within
the reservoirs in result of both fluid injection operations and
simultaneous drainage of the reservoir in resulting production
operations. The preferred permanent deployment status of the
sensors and generators of the invention permit and see to the
measurements simultaneously with ongoing injection flooding and
production operations. Advancements in both acoustic measurement
capabilities and signal processing while operating the flooding of
the reservoir represents a significant, technological advance in
that the prior art requires cessation of the injection/production
operations in order to monitor acoustic parameters downhole. As one
of ordinary skill in the art will recognize the cessation of
injection results in natural redistribution of the active flood
profile due primarily to gravity segregation of fluids and entropic
phenomena that are not present during active flooding operations.
This also enhances the possibility of premature breakthrough, as
oil migrates to the relative top of the formation and the injected
fluid, usually water, migrates to the relative bottom of the
formation. Hence, there is a significant possibility that the water
will actually reach the production well and thus further pumping of
steam or water will merely run underneath the layer of oil at the
top of the formation and the sweep of that region would be
extremely difficult thereafter.
[0059] In yet another embodiment of the invention fiber optics are
employed (similar to those disclosed in the U.S. application filed
on Jun. 10, 1997 entitled CHEMICAL INJECTION WELL CONTROL AND
MONITORING SYSTEM under Attorney docket number 97-1554 and BHI
197-09539-US which is fully incorporated herein by reference) to
determine the amount of and/or presence of biofouling within the
reservoir by providing a culture chamber within the injection or
production well, wherein light of a predetermined wavelength may be
injected by a fiber optical cable, irradiating a sample determining
the degree to which biofouling may have occurred. As one of
ordinary skill in the art will recognize, various biofouling
organisms will have the ability to fluoresce at a given wavelength,
that wavelength once determined, is useful for the purpose above
stated.
[0060] Referring back to FIG. 2, the flood front may also be
monitored from the "back" employing sensors 155 installed in the
injection well 106. These sensors provide acoustic signals which
reflect from the water/oil interface thus providing an accurate
picture in a moment in time of the three-dimensional flood front.
Taking real time 4D pictures provides an accurate format of the
density profile of the formation due to the advancing flood front.
Thus, a particular profile and the relative advancement of the
front can be accurately determined by the density profile changes.
It is certainly possible to limit the sensors and acoustic
generators to the injection well for such a system. However, it is
generally more preferable to also introduce sensors and acoustic
generators in the production well toward which the front is moving
(as described before) thus allowing an immediate double check of
the fluid front profile. That is, acoustic generators on the
production well will reflect a signal off the oil/water interface
and will provide an equally accurate three-dimensional fluid front
indicator. The indicators from both sides of the front should agree
and thus provides an extremely reliable indication of location and
profile. A common processor 151 may be used for processing data
from the wells 102-106.
[0061] Referring now to FIG. 5, the distributed fiber optic sensors
of the type described above are also well suited for use in a
production well where chemicals are being injected therein and
there is a resultant need for the monitoring of such a chemical
injection process so as to optimize the use and effect of the
injected chemicals. Chemicals often need to be pumped down a
production well for inhibiting scale, paraffins and the like as
well as for other known processing applications and pretreatment of
the fluids being produced. Often, as shown in FIG. 5, chemicals are
introduced in an annulus 400 between the production tubing 402 and
the casing 404 of a well 406. The chemical injection (shown
schematically at 408) can be accomplished in a variety of known
methods such as in connection with a submersible pump (as shown for
example in U.S. Pat. No. 4,582,131, assigned to the assignee hereof
and incorporated herein by reference) or through an auxiliary line
associated with a cable used with an electrical submersible pump
(such as shown for example in U.S. Pat. No. 5,528,824, assigned to
the assignee hereof and incorporated herein by reference).
[0062] In accordance with an embodiment of the present invention,
one or more bottomhole sensors 410 are located in the producing
zone 405 for sensing a variety of parameters associated with the
producing fluid and/or interaction of the injected chemical and the
producing fluid 407. Thus, the bottomhole sensors 410 will sense
parameters relative to the chemical properties of the produced
fluid such as the potential ionic content, the covalent content, pH
level, oxygen levels, organic precipitates and like measurements.
Sensors 410 can also measure physical properties associated with
the producing fluid and/or the interaction of the injected
chemicals and producing fluid such as the oil/water cut, viscosity
and percent solids. Sensors 410 can also provide information
related to paraffin and scale build-up, H.sub.2S content and the
like.
[0063] Bottomhole sensors 410 preferably communicate with and/or
are associated with a plurality of distributed sensors 412 which
are positioned along at least a portion of the wellbore (e.g.,
preferably the interior of the production tubing) for measuring
pressure, temperature and/or flow rate as discussed above in
connection with FIG. 1. The present invention is also preferably
associated with a surface control and monitoring system 414 and one
or more known surface sensors 415 for sensing parameters related to
the produced fluid; and more particularly for sensing and
monitoring the effectiveness of treatment rendered by the injected
chemicals. The sensors 415 associated with surface system 414 can
sense parameters related to the content and amount of, for example,
hydrogen sulfide, hydrates, paraffins, water, solids and gas.
[0064] Preferably, the production well disclosed in FIG. 5 has
associated therewith a so-called "intelligent" downhole control and
monitoring system which may include a downhole computerized
controller 418 and/or the aforementioned surface control and
monitoring system 414. This control and monitoring system is of the
type disclosed in U.S. Pat. No. 5,597,042, which is assigned to the
assignee hereof and fully incorporated herein by reference. As
disclosed in U.S. Pat. No. 5,597,042, the sensors in the
"intelligent" production wells of this type are associated with
downhole computer and/or surface controllers which receive
information from the sensors and based on this information,
initiate some type of control for enhancing or optimizing the
efficiency of production of the well or in some other way effecting
the production of fluids from the formation. In the present
invention, the surface and/or downhole computers 414, 418 will
monitor the effectiveness of the treatment of the injected
chemicals and based on the sensed information, the control computer
will initiate some change in the manner, amount or type of chemical
being injected. In the system of the present invention, the sensors
410 and 412 may be connected remotely or in-situ.
[0065] In a preferred embodiment of the present invention, the
bottomhole sensors comprise fiber optic chemical sensors. Such
fiber optic chemical sensors preferably utilize fiber optic probes
which are used as a sample interface to allow light from the fiber
optic to interact with the liquid or gas stream and return to a
spectrometer for measurement. The probes are typically composed of
sol gel indicators. Sol gel indicators allow for online, real time
measurement and control through the use of indicator materials
trapped in a porous, sol gel derived, glass matrix. Thin films of
this material are coated onto optical components of various probe
designs to create sensors for process and environmental
measurements. These probes provide increased sensitivity to
chemical species based upon characteristics of the specific
indicator. For example, sol gel probes can measure with great
accuracy the pH of a material and sol gel probes can also measure
for specific chemical content. The sol gel matrix is porous, and
the size of the pores is determined by how the glass is prepared.
The sol gel process can be controlled so as to create a sol gel
indicator composite with pores small enough to trap an indicator in
the matrix but large enough to allow ions of a particular chemical
of interest to pass freely in and out and react with the indicator.
An example of suitable sol gel indicator for use in the present
invention is shown in FIGS. 6 and 7.
[0066] Referring to FIGS. 6 and 7, a probe is shown at 416
connected to a fiber optic cable 418 which is in turn connected
both to a light source 420 and a spectrometer 422. As shown in FIG.
7, probe 416 includes a sensor housing 424 connected to a lens 426.
Lens 426 has a sol gel coating 428 thereon which is tailored to
measure a specific downhole parameter such as pH or is selected to
detect the presence, absence or amount of a particular chemical
such as oxygen, H.sub.2S or the like. Attached to and spaced from
lens 426 is a mirror 430. During use, light from the fiber optic
cable 418 is collimated by lens 426 whereupon the light passes
through the sol gel coating 428 and sample space 432. The light is
then reflected by mirror 430 and returned to the fiber optical
cable. Light transmitted by the fiber optic cable is measured by
the spectrometer 422. Spectrometer 422 (as well as light source
420) may be located either at the surface or at some location
downhole. Based on the spectrometer measurements, a control
computer 414, 416 will analyze the measurement and based on this
analysis, the chemical injection apparatus 408 will change the
amount (dosage and concentration), rate or type of chemical being
injected downhole into the well. Information from the chemical
injection apparatus relating to amount of chemical left in storage,
chemical quality level and the like will also be sent to the
control computers. The control computer may also base its control
decision on input received from surface sensor 415 relating to the
effectiveness of the chemical treatment on the produced fluid, the
presence and concentration of any impurities or undesired
by-products and the like.
[0067] Alternatively a spectrometer may be utilized to monitor
certain properties of downhole fluids. The sensor includes a glass
or quartz probe, one end or tip of which is placed in contact with
the fluid. Light supplied to the probe is refracted based on the
properties of the fluid. Spectrum analysis of the refracted light
is used to determine the and monitor the properties, which include
the water, gas, oil and solid contents and the density.
[0068] In addition to the bottomhole sensors 410 being comprised of
the fiber optic sol gel type sensors, distributed sensors 412 along
production tubing 402 may also include the fiber optic chemical
sensors of the type discussed above. In this way, the chemical
content of the production fluid may be monitored as it travels up
the production tubing if that is desirable.
[0069] The permanent placement of the sensors 410, 412 and control
system 417 downhole in the well leads to a significant advance in
the field and allows for real time, remote control of chemical
injections into a well without the need for wireline device or
other well interventions.
[0070] In accordance with the present invention, a novel control
and monitoring system is provided for use in connection with a
treating system for handling produced hydrocarbons in an oilfield.
Referring to FIG. 8, a typical surface treatment system used for
treating produced fluid in oil fields is shown. As is well known,
the fluid produced from the well includes a combination of
emulsion, oil, gas and water. After these well fluids are produced
to the surface, they are contained in a pipeline known as a "flow
line." The flow line can range in length from a few feet to several
thousand feet. Typically, the flow line is connected directly into
a series of tanks and treatment devices which are intended to
provide separation of the water in emulsion from the oil and gas.
In addition, it is intended that the oil and gas be separated for
transport to the refinery.
[0071] The produced fluids flowing in the flow line and the various
separation techniques which act on these produced fluids lead to
serious corrosion problems. Presently, measurement of the rate of
corrosion on the various metal components of the treatment systems
such as the piping and tanks is accomplished by a number of sensor
techniques including weight loss coupons, electrical resistance
probes, electrochemical--linear polarization techniques,
electrochemical noise techniques and AC impedance techniques. While
these sensors are useful in measuring the corrosion rate of a metal
vessel or pipework, these sensors do not provide any information
relative to the chemicals themselves, that is the concentration,
characterization or other parameters of chemicals introduced into
the treatment system. These chemicals are introduced for a variety
of reasons including corrosion inhibition and emulsion breakdown,
as well as scale, wax, asphaltene, bacteria and hydrate
control.
[0072] In accordance with an important feature of the present
invention, sensors are used in chemical treatment systems of the
type disclosed in FIG. 8 which monitors the chemicals themselves as
opposed to the effects of the chemicals (for example, the rate of
corrosion). Such sensors provide the operator of the treatment
system with a real time understanding of the amount of chemical
being introduced, the transport of that chemical throughout the
system, the concentration of the chemical in the system and like
parameters. Examples of suitable sensors which may be used to
detect parameters relating to the chemicals in the treatment system
include the fiber optic sensor described above with reference to
FIGS. 6 and 7. Ultrasonic absorption and reflection, laser-heated
cavity spectroscopy (LIMS), X-ray fluorescence spectroscopy,
neutron activation spectroscopy, pressure measurement, microwave or
millimeter wave radar reflectance or absorption, and other optical
and acoustic (i.e., ultrasonic or sonar) methods may also be used.
A suitable microwave sensor for sensing moisture and other
constituents in the solid and liquid phase influent and effluent
streams is described in U.S. Pat. No. 5,455,516, all of the
contents of which are incorporated herein by reference. An example
of a suitable apparatus for sensing using LIBS is disclosed in U.S.
Pat. No. 5,379,103 all of the contents of which are incorporated
herein by reference. An example of a suitable apparatus for sensing
LIMS is the LASMA Laser Mass Analyzer available from Advanced Power
Technologies, Inc. of Washington, D.C. An example of a suitable
ultrasonic sensor is disclosed in U.S. Pat. No. 5,148,700 (all of
the contents of which are incorporated herein by reference). A
suitable commercially available acoustic sensor is sold by Entech
Design, Inc., of Denton, Tex. under the trademark MAPS.RTM..
Preferably, the sensor is operated at a multiplicity of frequencies
and signal strengths. Suitable millimeter wave radar techniques
used in conjunction with the present invention are described in
chapter 15 of Principles and Applications of Millimeter Wave Radar,
edited by N. C. Currie and C. E. Brown, Artech House, Norwood,
Mass. 1987.
[0073] While the sensors may be utilized in a system such as shown
in FIG. 8 at a variety of locations, the arrows numbered 500,
through 516 indicate those positions where information relative to
the chemical introduction would be especially useful.
[0074] Referring now to FIG. 9, the surface treatment system of
FIG. 8 is shown generally at 520. In accordance with the present
invention, the chemical sensors (i.e. 500-516) will sense, in real
time, parameters (i.e., concentration and classification) related
to the introduced chemicals and supply that sensed information to a
controller 522 (preferably a computer or microprocessor based
controller). Based on that sensed information monitored by
controller 522, the controller will instruct a pump or other
metering device 524 to maintain, vary or otherwise alter the amount
of chemical and/or type of chemical being added to the surface
treatment system 520. The supplied chemical from tanks 526 can, of
course, comprise any suitable treatment chemical such as those
chemicals used to treat corrosion, break down emulsions, etc.
Examples of suitable corrosion inhibitors include long chain amines
or aminodiazolines. Suitable commercially available chemicals
include Cronox which is a corrosion inhibitor sold by Baker
Petrolite, a division of Baker-Hughes Incorporated, of Houston,
Tex.
[0075] Thus, in accordance with the control and monitoring system
of FIG. 9, based on information provided by the chemical sensors
500-516, corrective measures can be taken for varying the injection
of the chemical (corrosion inhibitor, emulsion breakers, etc.) into
the system. The injection point of these chemicals could be
anywhere upstream of the location being sensed such as the location
where the corrosion is being sensed. Of course, this injection
point could include injections downhole. In the context of a
corrosion inhibitor, the inhibitors work by forming a protective
film on the metal and thereby prevent water and corrosive gases
from corroding the metal surface. Other surface treatment chemicals
include emulsion breakers which break the emulsion and facilitate
water removal. In addition to removing or breaking emulsions,
chemicals are also introduced to break out and/or remove solids,
wax, etc. Typically, chemicals are introduced so as to provide what
is known as a base sediment and water (B.S. and W.) of less than
1%.
[0076] In addition to the parameters relating to the chemical
introduction being sensed by chemical sensors 500-516, the
monitoring and control system of the present invention can also
utilize known corrosion measurement devices as well including flow
rate, temperature and pressure sensors. These other sensors are
schematically shown in FIG. 9 at 528 and 530. The present invention
thus provides a means for measuring parameters related to the
introduction of chemicals into the system in real time and on line.
As mentioned, these parameters include chemical concentrations and
may also include such chemical properties as potential ionic
content, the covalent content, pH level, oxygen levels, organic
precipitates and like measurements. Similarly, oil/water cut
viscosity and percent solids can be measured as well as paraffin
and scale build-up, H.sub.2S content and the like. The fiber optic
sensors described above may be used to determine the above
mentioned parameter downhole.
[0077] FIG. 10 is a schematic diagram of a wellbore system 600
wherein a common conduit is utilized for operating a downhole
hydraulically-operated tool or device and for monitoring one or
more downhole parameters utilizing the fiber optics. System 600
includes a wellbore 602 having a surface casing 601 installed a
short distance from the surface 604. After the wellbore 102 has
been drilled to a desired depth. A completion or production string
606 is conveyed into the wellbore 602. The string 606 includes at
least one downhole hydraulically-operated device 614 carried by a
tubing 608 which tubing may be a drill pipe, coiled tubing or
production tubing. A fluid conduit 610 (or hydraulic line) having a
desired inner diameter 611 is placed or attached either on the
outside of the string 606 (as shown in FIG. 10) or in the inside of
the string in any suitable manner. The conduit 610 is preferably
routed at a desired location on the string 606 via a u-joint 612 so
as to provide a smooth transition for returning the conduit 610 to
the surface 604. A hydraulic connection 624 is provided from the
conduit 610 to the device 614 so that a fluid under pressure can
pass from the conduit 610 to the device 614. After the string 606
has been placed or installed at a desired depth in the wellbore
602, an optical fiber 612 is pumped under pressure at the inlet
630a from a source of fluid 630. The optical fiber 622 passes
through the entire length of the conduit 610 and returns to the
surface 604 via outlet 630b. The fiber 622 is then optically
coupled to a light source and recorder (or detector) (LS/REC) 640.
A data acquisition/signal processor (DA/SP) 642 processes
data/signal received via the optical fiber 622 and also controls
the operation of the light source and recorder 640.
[0078] The optical fiber 622 may include a plurality of sensors 620
distributed along its length. Sensors 620 may include temperature
sensors, pressure sensors, vibration sensors or any other fiber
optic sensor that can be placed on the fiber optic cable 622.
Sensors 620 are formed into the cable 622 during the manufacturing
of the cable 622. The downhole device 614 may be any downhole
fluid-activated device including but not limited to a valve, a
choke, a sliding sleeve, a perforating device, and a packer, fluid
flow regulation device, or any other completion and/or production
device. The device 614 is activated by supplying fluid under
pressure through the conduit 610. In the embodiment shown herein,
the line 610 receives fiber optic cable 622 throughout its length
and is connected to surface instrumentation 640 and 642 for
distributed measurements of downhole parameters along its length.
The line 610 may be arranged downhole along the string 606 in a V
or other convenient shape. Alternatively, the line 610 may
terminate at the device 614 and/or continue to a second device (not
shown) downhole. the fiber optic sensors also may be disposed on
the line in any other suitable manner such as wrapping them on the
outside of the conduit 610. In the present invention, a common line
is thus used to control a hydraulically-controlled device and to
monitor one or more downhole parameters along the line.
[0079] During the completion of the wellbore 602, the sensors 620
provide useful measurements relating to their associated downhole
parameters and the line 606 is used to actuate a downhole device.
The sensors 620 continue to provide information about the downhole
parameters over time.
[0080] FIG. 11 shows a schematic diagram of a producing well 702
that preferably has two electric submersible pumps ("ESP") 714, one
for pumping the oil/gas 706 to the surface 703 and the other to
pump any separated water back into a formation. The formation fluid
706 flows from a producing zone 708 into the wellbore 702 via
perforations 707. Packers 710a and 710b installed below and above
the ESP 714 force the fluid 706 to flow to the surface 703 via
pumps ESP 714. An oil water separator 750 separates the oil and
water and provide them to their respective pumps 714a-714b. A choke
752 provides desired back pressure. An instrument package 760 and
pressure sensor is installed in the pump string 718 to measure
related parameters during production. The present invention
utilizes optical fiber with embedded sensors to provide
measurements of selected parameters, such as temperature, pressure,
vibration, flow rate as described below. ESP's 714 use large
amounts of electric power which is supplied from the surface via a
power cable 724. Such cables often tend to corrode an/or
overheated. Due to the high power being carried by the cable 724,
electrical sensors are generally not placed on or along side the
cable 724.
[0081] In one embodiment of the present invention as shown in FIG.
11, a fiber optic cable 722 carrying sensors 720 is placed along
the power cable 724. The fiber optic cable 702 may also be extended
below the ESP's 714 to replace conventional sensors in the
instrumentation package 760 and to provide control signals to the
downhole device or processors as described earlier. In one
application, the sensors 720 measure vibration and temperature of
the ESP 714. It is desirable to operate the ESP at a low
temperature and without excessive vibration. The ESP 714 speed is
adjusted so as to maintain one or both such parameters below their
predetermined maximum value or within their respective
predetermined ranges. The fiber optic sensors are used in this
application to continuously or periodically determine the physical
condition (health) of the ESP The fiber optic cable 722 may be
extended or deployed below the ESP at the time of installing the
production string 718 in the manner described with respect to FIG.
10. It should be obvious that the use of the ESP is only one
example of the downhole device that can be used for the purposes of
this invention. The present invention may be used to continuously
measure downhole parameters, to monitor the health or condition of
downhole devices and to control downhole devices. Any suitable
device may be utilized for this purpose including, sliding sleeves,
packers, flow control devices etc.
[0082] FIG. 12 shows a wellbore 802 with a production string 804
having one or more electrically-operated or optically-operated
devices, generally denoted herein by numeral 850 and one or more
downhole sensors 814. The string 804 includes batteries 812 which
provide electrical power to the devices 850 and sensors 814. The
batteries are charged by generating power downhole by turbines (not
shown) or by supplying power from the surface via a cable (not
shown).
[0083] In the present invention a light cell 810 is provided in the
string 804 which is coupled to an optical fiber 822 that has one or
more sensors 820 associated therewith. A light source 840 at the
surface provides light to the light cell 810 which generates
electricity which charges the downhole batteries 812. The light
cell 810 essentially trickle charges the batteries. In many
applications the downhole devices, such as devices 850, are
activated infrequently. Trickle charging the batteries may be
sufficient and thus may eliminate the use of other power generation
devices. In applications requiring greater power consumption, the
light cell may be used in conjunction with other conventional power
generation devices.
[0084] Alternatively, if the device 850 is optically-activated, the
fiber 822 is coupled to the device 850 as shown by the dotted line
822a and is activated by supplying optical pulses from the surface
unit 810. Thus, in the configuration of FIG. 12, a fiber optics
device is utilized to generate electrical energy downhole, which is
then used to charge a source, such as a battery, or operate a
device. The fiber 822 is also used to provide two-way communication
between the DA/SP 842 and downhole sensors and devices.
[0085] FIG. 13 shows a schematic of a wellbore system 900 wherein a
permanently installed electrically-operated device is monitored and
controlled by a fiber optic based system. The system 900 includes a
wellbore 902 and an electically-operated device 904 installed at a
desired depth, which may be a sliding sleeve, a choke, a fluid flow
control device, etc. An control unit 906 controls the operation of
the device 904. A production tubing 910 installed above the device
904 allows formation fluid to flow to the surface 901. During the
manufacture of the string 911 that includes the device 904 and the
tubing 910, a conduit 922 is clamped along the length of the tubing
910 with clamps 921. An optical coupler 907 is provided at the
electrical control unit 906 which can mate with a coupler fed
through the conduit 922.
[0086] Either prior to or after placing the string 910 in the
wellbore 902, a fiber optic cable 921 is deployed in the conduit
922 so that a coupler 922a at the cable 921 end would couple with
the coupler 907 of the control unit 906. A light source 990
provides the light energy to the fiber 922. A plurality of sensors
920 may be deployed along the fiber 922 as described before. A
sensor preferably provided on the fiber 922 determines the flow
rate of formation fluid 914 flowing through the device 904. Command
signals are sent by DA/SP 942 to activate the device 904 via the
fiber 922. These signals are detected by the control unit 906,
which in turn operate the device 904. This, in the configuration of
FIG. 13, fiber optics is used to provide two way communication
between downhole devices, sensors and a surface unit and to operate
the downhole devices.
[0087] FIGS. 14A and 14B show a method monitoring the location of
prior wells during drilling of a wellbore so as to avoid drilling
the wellbore too close to or into the existing wellbores. Several
wellbores are sometimes drilled from a rig at a single location.
This is a common practice in offshore drilling because moving large
platforms or rigs is not practical. Often, thirty to forty
wellbores are drilled from a single location. A template is used to
define the relative location of the wells at the surface. FIGS. 14A
and 14B show wellbores 1004-1008 drilled from a common template
1005. The template 1005 shows openings 1004a, 1006a, and 1008a as
surface locations for the wellbores 1004, 1006 and 1008
respectively. Locations of all other wellbores drilled from the
template 1005 are referred to by numeral 1030. FIG. 14B also shows
a lateral or branch wellbore 1010 being drilled from the wellbore
1004, by a drill bit 1040. The wellbore 1008 is presumed to be
drilled before wellbores 1004 and 1010. For the purposes of this
example, it is assumed that the driller wishes to avoid drilling
the wellbore 1010 too close to or onto the wellbore 1008. Prior to
drilling the wellbore 1010, a plurality of fiber optic sensors 40
are disposed in the wellbore 1008. The vibrations of the drill bit
1040 during drillng of the wellbore 1010 generate acoustic energy,
which travels to the wellbore 1008 by a processor of the kind
described earlier. The sensors 40 in the well bore 1008 detect
acoustic signals received at the well bore 1008. The received
signals are processed and analyzed to determine the distance of the
drill bit from the wellbore 1008. The travel time of the acoustic
signals from the drill bit 1040 to the sensors 40 in the wellbore
1008 provides relatively accurate measure of such distance. The
fiber optic temperature sensor measurements are preferably used to
correct or compensate the travel time or the underlying velocity
for the effects of temperature. The driller can utilize this
information to ensure that the wellbore 1010 is being drilled at a
safe distance from the wellbore 1008, thereby avoiding drilling it
too close or into the wellbore 1008.
[0088] The fiber optic sensors described above are especially
suitable for use in drill strings utilized for drilling wellbores.
For the purposes of this invention, a "drill string" includes a
drilling assembly or bottom hole assembly ("BHA") carried by a
tubing which may be drill pipe or coiled tubing. A drill bit is
attached to the BHA which is rotated by rotating the drill pipe or
by a mud motor. FIG. 14C shows a bottomhole assembly 1080 having
the drill bit 1040 at one end. The bottomhole assembly 1080 is
conveyed by a tubing 1062 such as a drill pipe or a coiled-tubing.
A mud motor 1052 drives the drill bit 1040 attached to the bottom
hole end of the BHA. A bearing assembly 1055 coupled to the drill
bit 1040 provides lateral and axial support to the drill bit 1040.
Drilling fluid 1060 passes through the drilling assembly 1080 and
drives the mud motor 1052, which in turn rotates the drill bit
1040.
[0089] As described below, a variety of fiber optic sensors are
placed in the BHA 1080, drill bit 1040 and the tubing 1082.
Temperature and pressure sensors T4 and P5 are placed in the drill
bit for monitoring the condition of the drill bit 1040. Vibration
and displacement sensors VI monitor the vibration of the BHA and
displacement sensors Vi monitor the lateral and axial displacement
of the drill shaft and that of the BHA. Sensors T1-T3 monitor the
temperature of the elastomeric stator of the mud motor 1052, while
the sensors P1-P4 monitor differential pressure across the mud
motor, pressure of the annulus and the pressure of the fluid
flowing through the BHA. Sensors V1-V2 provide measurements for the
fluid flow through the BHA and the wellbore. Additionally a
spectrometric sensors S1 of the type described above may be placed
in a suitable section 1050 of the BHA to measure the fluid and
chemical properties of the wellbore fluid. Fiber optic sensor R1 is
used to detect radiation. Acoustic sensors S1-S2 may be placed in
the BHA for determining the acoustic properties of the formation.
Additionally sensors, generally denoted herein as S may be used to
provide measurements for resistivity, electric field, magnetic
field and other measurements that can be made by the fiber optic
sensors. A light source LS and the data acquisition and processing
unit DA are preferably disposed in the BHA. The processing of the
signals is preferably done downhole, but may be done at the
surface. Any suitable two way communication method may be used to
communicate between the BHA and the surface equipment, including
optical fibers. The measurements made are utilized for determining
formation parameters of the kind described earlier, fluid
properties and the condition of the various components of the drill
string including the condition of the drill bit, mud motor, bearing
assembly and any other component part of the drilling assembly.
[0090] While foregoing disclosure is directed to the preferred
embodiments of the invention, various modifications will be
apparent to those skilled in the art. It is intended that all
variations within the scope and spirit of the appended claims be
embraced by the foregoing disclosure.
* * * * *