U.S. patent application number 09/726294 was filed with the patent office on 2002-07-11 for system for separately producing water and oil from a reservoir.
Invention is credited to Chen, Min-Yi, Dhruva, Brindesh, Goode, Peter A., Nelson, Rod F., Ramakrishnan, Terizhandur S., Thambynayagam, Raj Kumar Michael.
Application Number | 20020088618 09/726294 |
Document ID | / |
Family ID | 24918004 |
Filed Date | 2002-07-11 |
United States Patent
Application |
20020088618 |
Kind Code |
A1 |
Ramakrishnan, Terizhandur S. ;
et al. |
July 11, 2002 |
System for separately producing water and oil from a reservoir
Abstract
A system for reservoir control. The system allows segregated
production of fluids, e.g. water and oil, to control the
fluid-fluid interface. Downhole sensors are utilized in providing
data about the location of the interface. This permits the
proactive monitoring and control of the interface prior to unwanted
intermingling of fluids, e.g. oil and water, during production.
Inventors: |
Ramakrishnan, Terizhandur S.;
(Bethel, CT) ; Dhruva, Brindesh; (Danbury, CT)
; Thambynayagam, Raj Kumar Michael; (Ridgefield, CT)
; Chen, Min-Yi; (West Redding, CT) ; Goode, Peter
A.; (Houston, TX) ; Nelson, Rod F.; (Sugar
Land, TX) |
Correspondence
Address: |
Patent Counsel
Schlumberger Reservoir Completions
Schlumberger Technology Corporation
P.O. Box 1590
Rosharon
TX
77583-1590
US
|
Family ID: |
24918004 |
Appl. No.: |
09/726294 |
Filed: |
November 30, 2000 |
Current U.S.
Class: |
166/250.02 ;
166/113; 166/369 |
Current CPC
Class: |
E21B 47/047 20200501;
E21B 43/32 20130101 |
Class at
Publication: |
166/250.02 ;
166/369; 166/113 |
International
Class: |
E21B 047/00 |
Claims
What is claimed is:
1. A method for reducing watercut during the production of a
desired production fluid from a well having a wellbore lined by a
wellbore casing, comprising: perforating the wellbore casing
proximate a production fluid zone and a water zone to permit
ingress of a production fluid and water into the wellbore;
producing the production fluid from the production fluid zone;
removing the water from the water zone to reduce watercut into the
production fluid zone; sensing the location of an interface between
the production fluid and the water via a sensor array deployed
external to the wellbore casing; and adjusting the rate at which at
least one of the production fluid and the water moves into the
wellbore based at least in part on the location of the
interface.
2. The method as recited in claim 1, wherein producing comprises
producing a petroleum product.
3. The method as recited in claim 2, wherein sensing comprises
utilizing an electrode sensor array.
4. The method as recited in claim 3, further comprising obtaining a
plurality of output values from the electrode sensor array and
utilizing those values in a reservoir model to determine whether a
change in the flow rate of the petroleum product or the water is
desired.
5. The method as recited in claim 3, wherein adjusting is based
directly on a plurality of output values from the electrode sensor
array.
6. The method as recited in claim 3, wherein producing the
petroleum product comprises producing the petroleum product through
a completion.
7. The method as recited in claim 6, wherein removing the water
comprises removing the water via a second completion.
8. The method as recited in claim 7, wherein the completion
comprises an electric submersible pumping system.
9. The method as recited in claim 8, wherein the second completion
comprises a second electric submersible pumping system.
10. The method as recited in claim 7, wherein removing comprises
removing the water to a location at the surface of the earth.
11. The method as recited in claim 7, wherein removing comprises
reinjecting the water at a subterranean location.
12. The method as recited in claim 7, wherein the completion
comprises a control valve.
13. The method as recited in claim 12, wherein the second
completion comprises a second control valve.
14. The method as recited in claim 3, wherein utilizing includes
deploying at least one electrode of the electrode sensor array as a
current emitter.
15. A method for determining and controlling the location of a
fluid-fluid interface along a wellbore used in the production of
oil, comprising: deploying a plurality of sensors along an exterior
of the wellbore above and below the fluid-fluid interface; and
outputting a signal from each sensor to indicate the presence of a
first fluid or a second fluid.
16. The method as recited in claim 15, wherein outputting comprises
outputting a signal indicative of oil as the first fluid.
17. The method as recited in claim 16, wherein outputting comprises
outputting a signal indicative of water as the second fluid.
18. The method as recited in claim 17, further comprising:
adjusting at least one of an oil production rate and a water
production rate based on the signals output from the plurality of
sensors.
19. The method as recited in claim 18, wherein deploying comprises
deploying an electrode array having a plurality of electrodes able
to output a voltage signal indicative of the presence of oil or
water.
20. The method as recited in claim 19, wherein deploying comprises
deploying at least one electrode that is a current emitter.
21. The method as recited in claim 19, wherein deploying comprises
locating the plurality of electrodes external to a wellbore casing
lining the wellbore.
22. The method as recited in claim 21, further comprising
determining the height of a hump in the oil-water interface remote
from the wellbore.
23. The method as recited in claim 19, wherein adjusting comprises
pumping the oil via an electric submersible pumping system.
24. The method as recited in claim 23, wherein adjusting comprises
pumping the water via a second electric submersible pumping
system.
25. The method as recited in claim 24, wherein pumping the water
includes directing the water to a subterranean injection
location.
26. The method as recited in claim 15, wherein outputting comprises
outputting a signal indicative of a gas as the first fluid.
27. A system for controlling an oil-water interface disposed about
a wellbore utilized in the production of an oil, comprising: a
first completion disposed within the wellbore for producing oil; a
second completion disposed within the wellbore for producing water;
and a sensor array disposed along the wellbore across an oil-water
interface formed between the oil and the water, wherein at least
one of the first and the second completions may be controlled to
adjust the location of the oil-water interface based on output from
the sensor array.
28. The system as recited in claim 27, wherein the sensor array
comprises a plurality of electrodes able to output signals that may
be used to determine the presence of an oil or a water.
29. The system as recited in claim 28, wherein the sensor array
comprises at least one electrode that is a current emitter.
30. The system as recited in claim 28, wherein the wellbore is
lined by a wellbore casing and the plurality of electrodes are
positioned outside the wellbore casing.
31. The system as recited in claim 28, wherein the first completion
comprises a control valve.
32. The system as recited in claim 28, wherein the first completion
comprises an electric submersible pumping system.
33. The system as recited in claim 28, wherein the second
completion comprises a control valve.
34. The system as recited in claim 28, wherein the second
completion comprises an electric submersible pumping system.
Description
FIELD OF THE INVENTION
[0001] The present invention relates generally to the production of
oil and water from a reservoir to limit the watercut or water
coning effects, and particularly to a system that utilizes an array
of sensors for sensing the oil and water interface to permit better
control over the movement of that interface.
BACKGROUND OF THE INVENTION
[0002] In some oil reservoirs, the oil production rate has been
limited by the inability to produce oil devoid of water. In
vertical wells, the upper limit of oil production rates has been
limited by watercutting, sometimes referred to as water coning,
where water is drawn into the oil zone perforations.
[0003] Water coning is caused by a hydraulic potential difference
between the fluid in the perforations and in the aquifer.
Basically, the radial pressure drop due to oil flow causes water to
rise towards the oil perforations. The rise of water to the oil
perforations may be limited by reducing the rate of oil production
but this, of course, greatly limits the "clean" oil production
rate.
[0004] Attempts have been made to produce both oil and water from
appropriately located oil perforations and water perforations to
prevent the draw of water into the oil perforations. The water
perforations are formed through the wellbore casing, and water is
removed from the aquifer through the perforations at a rate that is
estimated to reduce water coning. One problem in existent systems
is the difficulty of controlling the production rates of oil and
water to ensure that neither water coning nor oil coning into the
water perforation occurs. Because there is no dependable way to
determine the advent of water coning or oil coning, the production
rates of oil and/or water are adjusted only when water is found in
the produced oil or oil in the produced water. Once this occurs,
however, the produced oil or water is no longer clean, and
sometimes the coning effect is difficult to reverse.
SUMMARY OF THE INVENTION
[0005] According to the present technique, a sensor array is
utilized at a downhole location across the oil-water interface. The
sensors are designed to output signals from which the presence of
oil or water may be determined. The outputs generated are used, for
instance, either directly or in a model based on reservoir
characteristics. The sensors permit detection of movement in the
oil-water interface which, in turn, allows the production rate of
oil and/or water to be changed in a manner that will compensate for
the movement in the oil-water interface. Thus, the effects of water
coning or oil coning can be detected and limited or reversed at an
early stage of development.
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] The invention will hereafter be described with reference to
the accompanying drawings, wherein like reference numerals denote
like elements, and:
[0007] FIG. 1 is a front elevational view of an exemplary dual
completion used for the production of oil and water;
[0008] FIG. 2 is a front elevational view of an alternate dual
completion production system similar to FIG. 1;
[0009] FIG. 3 is another alternate embodiment of the dual
completion production system illustrated in FIG. 1;
[0010] FIG. 4 is an alternate embodiment of an oil and water
production system in which the water is reinjected at a separate
subterranean location;
[0011] FIG. 5 is a front elevational view of a system for producing
liquids from two separate production zones;
[0012] FIG. 6 is a flow chart illustrating an exemplary methodology
for utilizing data from sensors disposed through the interface
between the produced fluids;
[0013] FIG. 7 is an illustration similar to FIG. 5 showing
additional parameters of an interface formed between the produced
liquids;
[0014] FIG. 8A is a graphical representation of changes in the
sensor output relative to changes in the oil-water interface;
and
[0015] FIG. 8B is another graphical representation of changes in
the oil-water interface relative to changes in sensor output.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0016] In the following description, dual completions are used to
produce two liquids from a subterranean location. The differing
types of liquid are detected and the production rate of each liquid
is selected to control the interface formed between the liquids. In
a typical application, the system is utilized to enhance the
production of "clean" oil when an oil-water interface is formed
between oil at a high subterranean zone and water at a contiguous,
lower subterranean zone. Although the following discussion focuses
on the production of oil and the oil-water interface commonly found
in certain reservoirs, the system is not limited to use with those
specific liquids.
[0017] A variety of dual completions designs may be used for the
production of oil and water, as known to those of ordinary skill in
the art now and in the future. However, a few general applications
are described herein to enhance an understanding of the system and
method for controlling the production of oil and water in a way
that limits the formation of water coning or oil coning.
[0018] Referring generally to FIG. 1, a production system 10 for
the controlled production of oil and water is illustrated. System
10 includes a dual completion having a water production completion
12 and an oil production completion 14. The dual completion is
deployed in a wellbore 16 typically lined by a wellbore casing
18.
[0019] Wellbore casing 18 includes a plurality of openings through
which production fluids flow into wellbore 16. For example, the
plurality of openings may include a set of oil perforations 20
through which oil flows into wellbore 16 for production along a
fluid flow path 22. Similarly, wellbore casing 18 includes a
plurality of water perforations 24 through which water flows into
wellbore 16.
[0020] In the illustrated embodiment, wellbore 16 is formed in a
geological formation 26 having an oil zone 28 disposed generally
above a water zone 30. Oil perforations 20 are located within oil
zone 28 to permit the inflow of oil into wellbore 16, and water
perforations 24 are disposed within water zone 30 to permit the
inflow of water into wellbore 16. An oil-water interface 32 forms
the boundary between the oil zone 28 and the water zone 30 and is
preferably maintained between oil perforations 20 and water
perforations 24. As described above, in the event removal of oil
from oil zone 28 is at too great a rate relative to the production
of water from water zone 30, water coning can occur in which water
cuts into the production of oil and enters oil perforations 20.
Contrariwise, if the relative production rate of water from water
zone 30 is too great, oil coning can occur where the oil-water
interface 32 is drawn towards water perforations 24 until oil is
drawn through perforations 24.
[0021] Within wellbore 16, the inflow of oil from oil zone 28 is
separated from the inflow of water through water perforations 24 by
a separation device, such as a packer 34. Packer 34 is deployed to
permit the separate production of water through water completion 12
and oil through oil completion 14. Effectively, packer 34 divides
the wellbore 16 into a lower water zone and an upper oil zone by
preventing mixing of oil and water after the liquids enter wellbore
16.
[0022] Changes in the position of the oil-water interface 32 are
detected by a plurality of sensors 36 disposed along wellbore 16
and across oil-water interface 32. Individual sensors of the array
of sensors 36 are designed to detect the presence of a given
liquid. A signal is output from each sensor to indicate the
presence of, for example, either oil or water. Thus, movement of
the oil-water interface 32 can be detected as it moves vertically
from one sensor to the next along wellbore 16.
[0023] One exemplary plurality of sensors 36 includes an array of
electrodes. The array of electrodes permits real-time sensing and
controlling of the production rates of oil and/or water. Due to the
conductivity contrast between oil and water, the electrodes provide
direct information regarding the movement of the oil-water
interface. For example, the electrodes can be used as passive
voltage measuring sensors able to output a signal indicative of the
presence of oil or water. In an exemplary embodiment, one or more
of the electrodes are used for current transmission while the
remaining electrodes are used as passive voltage measuring sensors.
In the embodiment illustrated, the electrodes extend along the
exterior of wellbore casing 18 above, between and below the oil
perforations and the water perforations.
[0024] The signals output by sensors 36 are transferred to a
receiving station 38 that preferably also functions as a controller
for controlling the flow rates of liquid through one or both of the
water completion 12 and the oil completion 14. Specific use of the
data received from sensor array 36 may vary depending on the
specific environment and application. For example, the data of
voltages/currents, pressures and flow rates may be used in
conjunction with a reservoir model. In this application, a
reservoir model is constructed to compute values for various
production and formation parameters, e.g. given the flow rates and
reservoir parameters, saturation levels, conductivities, pressures
and the electrode potentials may be computed. The computed values
are compared to the observed data, and the reservoir model is
iteratively updated. The fluid production rates are adjusted
according to new optimization calculations for the model.
[0025] In another exemplary application, the data output from
sensors 36 is used directly rather than in conjunction with a
reservoir model. In this approach, an estimate for the desired
electrode sensor values or interface locations is made and a
control algorithm is determined to adjust the flow rate(s) of the
oil and/or water in a manner that maintains the electrode sensor
values or the estimated oil-water interface at a desired level.
This approach allows direct observation of the formation rather
than carrying out reservoir model updates. This latter approach may
be called observation-based control.
[0026] Regardless of whether the sensor data is used directly or in
conjunction with a reservoir model, the receiving
station/controller 38 utilizes the data output by sensors 36 to
adjust one or both of the flow rates of water and oil. For example,
in one type of production application, controller 38 is coupled to
an oil control valve 40 and a water control valve 42, shown
schematically in FIG. 1. Control valves 40 and 42 can be adjusted
to permit increased or decreased flow of oil and/or water.
[0027] Receiving/control station 38 can be constructed according to
a variety of designs. The station could be constructed to present
information from sensors 36 to an operator who would then, based on
this information, adjust the oil and/or water flow rates.
Alternatively, receiving station 38 can utilize a computer
programmed to appropriately analyze the data received from sensors
36 and automatically adjust one or both of the oil and water flow
rates, as would be understood by one of ordinary skill in the
art.
[0028] Also, a variety of sensors 36 can be used to detect the
oil-water interface 32. However, when sensors, such as electrodes
are utilized, the sensors preferably are deployed along wellbore 16
external to wellbore casing 18. This permits direct contact of
sensors 36 with the surrounding oil or water.
[0029] In FIG. 1, a representative system for producing oil and
water is illustrated, but a variety of systems may be utilized. For
example, rather than control valves, an electric submersible
pumping (ESP) system 44 may be utilized, as illustrated in FIG. 2.
In this embodiment, an ESP system pumps or produces water along a
water flow path 46. Receiving/control station 38 is utilized in
selecting the appropriate operating speed of electric submersible
pumping system 44 to control the flow of water based on the output
from sensors 36. Depending on the type of formation and the natural
pressure acting on oil zone 28, the production of oil along oil
flow path 22 may be controlled by, for example, a control valve or
another electric submersible pumping system. Electric submersible
pumping systems are used, for instance, when the natural well
pressure is not sufficient to raise the liquid to the surface of
the earth.
[0030] One example of a dual completion having dual electric
submersible pumping systems is illustrated in FIG. 3. In this
embodiment, water is produced along water flow path 46 by electric
submersible pumping system 44, and oil is produced along oil flow
path 22 by a second electric submersible pumping system 48. By way
of example, water may be produced through a tubing string 50, and
oil may be produced through a second tubing string 52. The pump
speed of either or both electric submersible pumping systems 44 and
48 may be adjusted to control one or both of the oil and water
production rates and consequently the oil-water interface proximate
wellbore casing 18.
[0031] Alternatively, water may be produced to a subterranean
location 54, as illustrated in FIG. 4. In this exemplary
embodiment, electric submersible pumping system 44 directs the
water downwardly along water flow path 46 through a tubing 56.
Tubing 56 extends through a lower packer 58 that separates the
water intake portion of wellbore 16 from the water injection
portion of wellbore 16. As illustrated, water is discharged beneath
lower packer 58 into wellbore 16 through a discharge end 60. The
water is then forced or injected into formation 26 through a
plurality of perforations 62. Again, the production rates of oil
and/or water can be controlled based on data received from sensors
36, e.g. electrodes disposed along the exterior of the wellbore
casing above, between and below perforations 20, 24 and 62. Thus, a
variety of oil and water production systems can be utilized in
controlling oil-water interface 32.
[0032] The data output from sensors 36 can be utilized in a variety
of ways to observe and control the oil-water interface 32.
Accordingly, the model based control and observation based control
methods discussed herein are merely exemplary utilizations of the
data provided. For purposes of this discussion, it may be assumed
that sensors 36 comprise an electrode array disposed on the outside
of wellbore casing 18.
[0033] In the model based control example, geological formation 26
is initialized with available knowledge, such as seismics, the
known geology and wellbore logs. Properties, such as
permeabilities, capillary pressures and relative permeabilities are
estimated, often based on core data obtained for the specific
geological formation, as known to those of ordinary skill in the
art.
[0034] Based on this available knowledge, a reservoir simulation
program (e.g. ECLIPSE.TM., available from Geoquest) is run to
determine optimal completion distances z.sub.o and z.sub.w, as
illustrated in FIG. 5. The distance z.sub.o represents the distance
between oil perforations 20 and the original oil-water interface
32. Similarly, the distance z.sub.w represents the desired distance
between water perforations 24 and the oil-water interface 32. Based
on formation properties, the estimated flow rates of water
(q.sub.w) and oil (q.sub.w) out of formation 26 also are estimated.
When water completion 12 and oil completion 14 are operated to
achieve the estimated flow rates, a full flow simulation may be
carried out based on the flow rates and the formation properties.
For example, saturation and concentration data may be used to
estimate current/voltages at the various electrode sensor
locations. Typically, the saturation and concentration data is
converted into conductivity values through suitable petrophysical
transformations to facilitate comparison of the estimated
current/voltages at the sensor locations with the actual data
provided by sensors 36. All of the accumulated data at various time
points may be compared with the actual measured values from sensors
36 to update parameters of the model and predict optimal production
values on an iterative basis, e.g. according to the least squares
method.
[0035] The general reservoir model approach is illustrated best in
FIG. 6. As discussed above, flow and formation data 62 from a flow
control device 63, e.g. a pump or valve, are utilized in creating a
model of the reservoir 64. From this reservoir model, petrophysics
(block 66) can be utilized to convert saturation and salinity
distribution data 68 into estimated conductivity distributions 70
across electrode array 36. The conductivity distributions are
applied to an electromagnetics model 72, and compared with actual
output from electrodes 36. The actual electrode responses 73 are
used with other data 74, e.g. pressure and voltage data, to
initialize and update flow rates (see reference numeral 75) and,
consequently, the flow data 62 used by reservoir model 64.
Typically, the electrode responses 73, data 74, and computed data
77, e.g. computed pressures, are compared and used to update flow
rates on an iterative basis (see block 76). Based on the
continuously updated reservoir model, the production rates of oil
(q.sub.o) and/or water (q.sub.w) are adjusted to maintain a desired
oil-water interface at a location that mitigates or reduces water
coning. As recognized by those of ordinary skill in the art, the
actual reservoir model and the data utilized in constructing and
updating the model may vary between reservoirs and
applications.
[0036] Alternatively, an observation based control methodology may
be used to limit oil and water incursion into the water and oil
completions, respectively. Control of the oil and/or water
production can be accomplished based either directly on the sensor
voltages/currents or through the estimated interface location.
Production control, based directly on the sensor voltages/currents,
relies on the difference between measured sensor values and the
desired sensor values determined from knowledge of the sensor
physics and output relative to surrounding environment. If, on the
other hand, the control is based on estimated interface location, a
control algorithm is utilized to maintain the oil-water interface
32 at a specific location to limit mingling of fluids in the
production stream. By way of example, oil-water interface 32 is
observed either directly or through inference based on computations
as discussed herein.
[0037] In an exemplary application, a control algorithm is used to
drive the oil-water interface 32 to a desired interface location.
In this example, it can be assumed that the reservoir in the region
of interest is homogeneous. Also, the array of electrodes 36 is
disposed on the outside of wellbore casing 18, as illustrated in
FIG. 7. Exemplary sensors 36 include one (or two) current providing
(return) electrodes (80). These current electrode(s) are rotated
among sensors 36 so that the remainder of the sensors function as
voltage electrodes. When one current electrode operates as an
injector, the return is at infinity, and the other electrodes
function as voltage measuring electrodes. By definition, the
voltage electrodes draw negligible current. In another mode,
voltages can be maintained at the electrodes, and measured currents
can be injected.
[0038] Any substantial change in formation resistivity between the
voltage electrodes 82 is easily detected, because the leakage
current from the wellbore to the formation changes. Because the
formation current is proportional to the gradient in the potential
along the wellbore, any change in the formation current is
reflected in terms of a jump in the derivative of electrical
potentials along the wellbore. The electrodes that straddle this
particular region are sufficient to indicate the region of
saturation change and a marker for this region may be established.
In a situation where the electrodes are kept at a constant
potential (and current injected is measured instead), a jump in the
current injected is the position of the region of saturation change
at the wellbore. Thus, in this situation, it is straightforward to
detect the nominal position of the water encroachment based on the
voltage or current measurements of electrodes at the region of
saturation change. Accordingly, the production rate of oil and/or
water can be adjusted to maintain the oil-water interface 32 at a
desired location.
[0039] However, in some environments, a hump or an anomalous rise
of oil-water contact 84 develops in addition to the oil-water
interface surrounding wellbore casing 18, as illustrated in FIG. 7.
The hump may develop away from the wellbore at distances comparable
to the thickness of the formation being produced. Computations have
shown that for a fixed ratio of oil to water production, the
rise-height of the hump 84 is governed predominantly by the oil
production rate. Thus, in such environments, increasing the oil
rate increases the water hump which, upon reaching a certain size,
can lead to breakdown of the dual production system.
[0040] It has been determined that the production rates can be
controlled not only for the oil-water contact close to the wellbore
but also for control of hump 84. If a hump is formed by the
advancing water, the rise height of the hump may be an important
factor in observation based control. However, the height of the
distant hump 84 can be obtained through data provided by sensors
36. (See FIGS. 8A and 8B).
[0041] In this particular example, we can assume that the height of
the water-oil contact close to the wellbore is equal to z.sub.n and
that the height of the hump 84 is z.sub.f. Based on prior
simulations, the desired position of z.sub.n and z.sub.f, i.e., the
set points, can be labeled as z.sub.sn and z.sub.sf, respectively.
The errors in the near and far rise are established by the
equations
.epsilon..sub.n=z.sub.n-z.sub.sn,
[0042] and
.epsilon..sub.f=z.sub.f-z.sub.sf.
[0043] If submersible pumps are used for the production of water
and oil as with the electric submersible pumping systems 44 and 48
of FIG. 3, the pumps may be operated to produce a flow rate on the
basis of 1 q w q o t = k bb n + k bt j
[0044] where the k.sub.bt term is expected to be small compared to
the first.
[0045] The oil rate is controlled by 2 q o t = k tt f + k tb n
[0046] where the k.sub.tb term is again expected to be small. All
of the k terms are control constants that will vary depending on
the application and formation but are best obtained by direct flow
and electromagnetics simulation of the reservoir. The k values do
not need to be optimized strictly but rather k values can be
selected that appear to produce a reasonable response. An
alternative to the above equations for controlling the ratio of
water to oil rates, involves directly choosing to control water
rates based on the errors C. Also, depending the formation
characteristics and the devices used for producing water and oil
(e.g. control valves), additional or different terms may be
required to better approximate the flow rates required to
adequately control the oil-water interface.
[0047] Referring to FIGS. 8A and 8B, examples of actual electrode
array responses are provided that reflect water rise height near
the wellbore (z.sub.n) and rise height of the hump 84 (z.sub.f). In
this example, the original oil-water interface was at approximately
1,120 feet and has moved up to 1,115 feet at the wellbore during
production. This change, z.sub.n, is seen as a discontinuity in the
derivative of voltages output by electrodes 82. The computation of
z.sub.n is straightforward based on the output from sensors 36, as
best illustrated in FIG. 8A.
[0048] In this same example, the movement of the hump is detected
(and therefore inverted) from the electrode array data, as
illustrated in FIG. 8B. In this sample, the difference in the
computed response based on output from sensors 36 provides an
estimated hump height change of 5 feet.
[0049] However, it should be noted that the discussion above is
merely of exemplary uses of the data provided by sensor array 36.
The actual calculation of a hump height may or may not be
necessary, depending on the particular formation and the production
rates. Additionally, the production equipment, conductivity of the
liquids being produced, formation characteristics, type of sensor
array 36, etc. all affect the formulas, models or direct usage of
the output data. However, the data can readily by adapted to aid in
the real time monitoring and control of fluid production for
preventing intermingling of liquids due to water coning or oil
coning.
[0050] It will be understood that the foregoing description is of
exemplary embodiments of this invention, and that the invention is
not limited to the specific forms shown. For example, variety of
sensors may be utilized, e.g. a distribution of pressure sensors or
acoustic sensors. Similar to segregated oil/water production, it is
to be understood that a gas/oil interface may be detected (by, for
example, acoustic sensors) and controlled by adjusting gas and oil
rates similar to adjustment of the oil and water rates based on the
equations given above for the oil/water system. Also, the procedure
described above can be further extended to include segregated three
phase production of gas, oil and water. Furthermore, different
types of completions and arrangements of completions can be
utilized to remove oil and water from the formation; and the models
or algorithms used in estimating any changes in liquid production
rates may be adjusted according to the environment and specific
application. These and other modifications may be made in the
design and arrangement of the elements without departing from the
scope of the invention as expressed in the appended claims.
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