U.S. patent application number 10/012221 was filed with the patent office on 2002-07-25 for measuring of fluid level in a well.
Invention is credited to Burris, Sanford A., Hill, David R., Scheucher, Karl F..
Application Number | 20020096323 10/012221 |
Document ID | / |
Family ID | 25490937 |
Filed Date | 2002-07-25 |
United States Patent
Application |
20020096323 |
Kind Code |
A1 |
Burris, Sanford A. ; et
al. |
July 25, 2002 |
Measuring of fluid level in a well
Abstract
A method of using a variety of sonic transmissions is utilized
to determine fluid level in a well. It is known that wells
replenish fluid at different rates even in the same formation or
well field. Maximum production at minimum pumping cost is achieved
for a given well.
Inventors: |
Burris, Sanford A.;
(Kirtland, OH) ; Hill, David R.; (Lorain, OH)
; Scheucher, Karl F.; (Waite Hill, OH) |
Correspondence
Address: |
COLLINS, CARY & ASSOCIATES
POST OFFICE BOX 41040
BRECKSVILLE
OH
44141-0040
US
|
Family ID: |
25490937 |
Appl. No.: |
10/012221 |
Filed: |
December 5, 2001 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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10012221 |
Dec 5, 2001 |
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09610204 |
Jul 4, 2000 |
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09610204 |
Jul 4, 2000 |
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08950856 |
Oct 15, 1997 |
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6085836 |
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Current U.S.
Class: |
166/250.03 ;
166/369 |
Current CPC
Class: |
G01F 23/2962 20130101;
E21B 47/047 20200501; E21B 47/008 20200501 |
Class at
Publication: |
166/250.03 ;
166/369 |
International
Class: |
E21B 047/00 |
Claims
What is claimed is:
1. A method to set pump activate and pump inactivate conditions, in
a well containing a pumpable liquid, to pump the liquid comprising:
transmitting a first continuous sonic signal at a first frequency
to a well casing thereby creating a reflected well casing sonic
signal; receiving the reflected well casing sonic signal from first
sonic signal; transmitting a second continuous sonic signal at a
second frequency, different than said first frequency, to a well
tubing thereby creating a reflected well tubing sonic signal;
receiving a reflected well tubing sonic signal from said second
sonic signal; transmitting a third continuous sonic signal at a
third frequency, different than said first frequency and different
than said second frequency, to the well annulus; receiving a
reflected well annulus sonic signal from said third sonic signal;
utilizing at least one of the reflected signals corresponding to
the transmitted signal to determine an initial liquid level P2 of
the well; pumping the liquid from the well until the well is at a
no liquid pumpable state P0; utilizing at least one of the
reflected signals corresponding to the transmitted signal to
determine the no liquid pumpable state P0; storing the data
generated from the reflected signal used at the no liquid pumpable
state P0; storing the data generated from the corresponding
transmitted signal at the initial liquid level P2 of the well;
continuously monitoring the liquid level of the well and converting
the data generated to activate the pump to pump the liquid at a
liquid level less than or equal to the initial liquid level P2;
continuously monitoring the liquid level of the well and converting
the data generated to inactivate the pump at a liquid level P1
above the no liquid pumpable state P0; thereby activating the pump
and inactivating the pump to pump the liquid.
2. The method of claim 1 wherein the data generated from the
transmitted signals and the reflected signals are averaged to
determine at least one of P0 and P2.
3. The method of claim 1 wherein all three of the reflected signals
corresponding to the transmitted signals are utilized to determine
the no liquid pumpable state P0.
4. The method of claim 1 wherein all three of the reflected signals
corresponding to the transmitted signals are utilized to determine
the initial liquid level P2 of the well.
5. The method of claim 1 wherein the transmitted signals and the
reflected signals are averaged to determine the P1 level.
6. The method of claim 1 wherein the transmitted signals and the
reflected signals are utilized to determine the P1 level.
7. The method of claim 1 wherein the data generated from the
transmitted signals and the reflected signals are averaged to
determine at least one of P0 and P2.
8. The method of claim 1 wherein the pumpable liquid is petroleum
based.
9. The method of claim 1 wherein the pumpable liquid is aqueous
based.
10. A method to set pump activate and pump inactivate conditions,
in a well containing a pumpable liquid, to pump the liquid
comprising: selectively transmitting a first sonic signal at a
first frequency to a well casing thereby creating a reflected well
casing sonic signal; receiving the reflected well casing sonic
signal, when said first sonic signal is transmitted, from said
first sonic signal; selectively transmitting a second sonic signal
at a second frequency, different than said first frequency, to a
well tubing thereby creating a reflected well tubing sonic signal;
receiving a reflected well tubing sonic signal, when said second
sonic signal is transmitted, from said second sonic signal;
selectively transmitting a third sonic signal at a third frequency,
different than said first frequency and different than said second
frequency, to the well annulus; receiving a reflected well annulus
sonic signal, when said third sonic signal is transmitted;
utilizing at least two of the reflected signals from the
corresponding transmitted signals to determine the initial liquid
levels P2 of the well; pumping the liquid from the well until the
well is at a no liquid pumpable state P0; utilizing at least two of
the reflected signals corresponding to the transmitted signals to
determine the no liquid pumpable state P0; storing the data
generated from the reflected signals used at the no liquid pumpable
state P0; storing the data generated from the corresponding
transmitted signal at the initial liquid level P2 of the well;
monitoring the liquid level of the well and converting the data
generated to activate the pump to pump the liquid at a liquid level
less than or equal to the initial liquid level P2; monitoring the
liquid level of the well and converting the data generated to
inactivate the pump at a liquid level P1 above the no liquid
pumpable state P0; thereby activating the pump and inactivating the
pump to pump the liquid.
11. The method of claim 10 wherein the data generated from the
transmitted signals and the reflected signals are averaged to
determine at least one of P0 and P2.
12. The method of claim 10 wherein all three of the reflected
signals corresponding to the transmitted signals are utilized to
determine the no liquid pumpable state P0.
13. The method of claim 10 wherein all three of the reflected
signals corresponding to the transmitted signals are utilized to
determine the initial liquid levels P2 of the well.
14. The method of claim 10 wherein the transmitted signals and the
reflected signals are averaged to determine the P1 level.
15. The method of claim 10 wherein the transmitted signals and the
reflected signals are utilized to determine the P1 level.
16. The method of claim 10 wherein the data generated from the
transmitted signals and the reflected signals are averaged to
determine at least one of P0 and P2.
17. The method of claim 10 wherein the pumpable liquid is petroleum
based.
18. The method of claim 10 wherein the pumpable liquid is aqueous
based.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] The present invention relates to determining the level of a
fluid in a well such as an oil well or water well.
[0003] 2. Description of the Art Practices
[0004] It is known that wells replenish fluid at different rates
even in the same formation or well field. The maximum production
from a given well occurs when the fluid level in the well bore is
as low as possible compared to the level in the surrounding
formation. The rate of fluid flow into the well bore (production)
is maximized then because the hydrostatic head driving the fluid is
at a maximum.
[0005] The preceding observation suggests that the well pump should
run constantly to keep the level in the well bore as low as
possible thus maximizing production. Of course, this is
unsatisfactory for several reasons.
[0006] First, running the pump constantly or at too great a speed
is inefficient since, some of the time, the well bore is completely
empty and there is nothing to pump. Thus energy conservation
becomes a cost consideration. Second, the equipment is subject to
wear and damage resulting in costly repairs when pumps are run dry.
Third, paraffin build up is more pronounced when a well is allowed
to pump dry. In the dry pump condition gases are drawn into the
bore. The gases in the bore then expand and cool. As the gases
cool, paraffin build up is promoted as these high melting
hydrocarbons begin to plate out on the surfaces of the bore.
[0007] Given the above considerations, control strategies aimed at
optimizing well production have emerged. Notably, timers have been
used to control the pump duty cycle. A timer may be programmed to
run the well nearly perfectly if the one could determine the
duration of the on cycle and off cycle which keeps the fluid level
in the bore low but which does not pump the bore dry, and if steady
conditions in the bore and with the equipment prevail.
[0008] The pump on cycle and off cycle can be determined for a
group of wells or for an entire well field. Savings in energy may
be maximized by knowing which wells fill at what rate and then
optimizing pumping to reduce or maintain a constant electric load
below the maximum peak available.
[0009] Given fluid level information, deciding when or how fast to
run the pump is very straight forward and production can be
optimized. Fluid level determinations, particularly for deep down
hole (bore) systems, have been implemented. Unfortunately, these
deep down hole have been costly and complex to install, unreliable
in operation, and costly to repair or service. Although the
implementation details will not be discussed here, it is worth
noting that these systems, when operating correctly, have proven
that significant gains in well production are available when
control strategies using fluid level measurement are applied.
[0010] Clearly, what is needed is a control system with the
advantages of fluid level measurement which is cost effective to
install and operate and which is reliable. Basic features for fluid
level measurement should include applicability to oil, water, or
other wells and should be applicable to rod, screw, or other pump
types.
[0011] An fluid level measurement system should be simple and
inexpensive to install in the T-Head and useful for well depths to
10,000 feet. Such a fluid level measurement system should be self
calibrating for each installation an accurate to 10 feet (3.1
meters) and robust to harsh environments within and around the
well.
SUMMARY OF THE INVENTION
[0012] In a first aspect, the present invention deals with a method
to set pump activate and pump inactivate conditions, in a well
containing a pumpable liquid, to pump the liquid comprising:
[0013] transmitting a first continuous sonic signal at a first
frequency to a well casing thereby creating a reflected well casing
sonic signal;
[0014] receiving the reflected well casing sonic signal from first
sonic signal;
[0015] transmitting a second continuous sonic signal at a second
frequency, different than said first frequency, to a well tubing
thereby creating a reflected well tubing sonic signal;
[0016] receiving a reflected well tubing sonic signal from said
second sonic signal;
[0017] transmitting a third continuous sonic signal at a third
frequency, different than said first frequency and different than
said second frequency, to the well annulus;
[0018] receiving a reflected well annulus sonic signal from said
third sonic signal;
[0019] utilizing at least one of the reflected signals
corresponding to the transmitted signal to determine an initial
liquid level P2 of the well;
[0020] pumping the liquid from the well until the well is at a no
liquid pumpable state P0;
[0021] utilizing at least one of the reflected signals
corresponding to the transmitted signal to determine the no liquid
pumpable state P0;
[0022] storing the data generated from the reflected signal used at
the no liquid pumpable state P0;
[0023] storing the data generated from the corresponding
transmitted signal at the initial liquid level P2 of the well;
[0024] continuously monitoring the liquid level of the well and
converting the data generated to activate the pump to pump the
liquid at a liquid level less than or equal to the initial liquid
level P2;
[0025] continuously monitoring the liquid level of the well and
converting the data generated to inactivate the pump at a liquid
level P1 above the no liquid pumpable state P0;
[0026] thereby activating the pump and inactivating the pump to
pump the liquid.
[0027] A second aspect of the invention is a method to set pump
activate and pump inactivate conditions, in a well containing a
pumpable liquid, to pump the liquid comprising:
[0028] selectively transmitting a first sonic signal at a first
frequency to a well casing thereby creating a reflected well casing
sonic signal;
[0029] receiving the reflected well casing sonic signal, when said
first sonic signal is transmitted, from said first sonic
signal;
[0030] selectively transmitting a second sonic signal at a second
frequency, different than said first frequency, to a well tubing
thereby creating a reflected well tubing sonic signal;
[0031] receiving a reflected well tubing sonic signal, when said
second sonic signal is transmitted, from said second sonic
signal;
[0032] selectively transmitting a third sonic signal at a third
frequency, different than said first frequency and different than
said second frequency, to the well annulus;
[0033] receiving a reflected well annulus sonic signal, when said
third sonic signal is transmitted;
[0034] utilizing at least two of the reflected signals from the
corresponding transmitted signals to determine the initial liquid
levels P2 of the well;
[0035] pumping the liquid from the well until the well is at a no
liquid pumpable state P0;
[0036] utilizing at least two of the reflected signals
corresponding to the transmitted signals to determine the no liquid
pumpable state P0;
[0037] storing the data generated from the reflected signals used
at the no liquid pumpable state P0;
[0038] storing the data generated from the corresponding
transmitted signal at the initial liquid level P2 of the well;
[0039] monitoring the liquid level of the well and converting the
data generated to activate the pump to pump the liquid at a liquid
level less than or equal to the initial liquid level P2;
[0040] monitoring the liquid level of the well and converting the
data generated to inactivate the pump at a liquid level P1 above
the no liquid pumpable state P0;
[0041] thereby activating the pump and inactivating the pump to
pump the liquid.
BRIEF DESCRIPTION OF THE DRAWINGS
[0042] Further features of the present invention will become
apparent to those skilled in the art to which the present invention
relates from reading the following specification with reference to
the accompanying drawings, in which:
[0043] FIG. 1 is a schematic of the electronic components.
[0044] FIG. 2 is a partial sectional view of a well head system;
and
DETAILED DESCRIPTION OF THE INVENTION
[0045] The basic components of an acoustical measurement system are
a Digital Signal Generator 10 which is a programmable generator
capable of generating arbitrary wave forms in the sub-sonic to
ultra-sonic bands. An Output Amplifier 20--drives a transmitter at
varying amplitudes with the signals from the Digital Signal
Generator 10.
[0046] A series of Acoustic Transmitters 30, 32, and 34 converts
the drive signal from the Output Amplifier 20 into a pressure wave.
A series of Acoustic Receivers 40, 42 and 44 receives reflected
acoustic signals from the Acoustic Transmitters 30, 32, and 34.
[0047] An Input Amplifier 50 conditions and amplifies signals from
the Acoustic Receivers 40, 42 and 44 and provides appropriate
output levels to a Digital Signal Analyzer 60.
[0048] The Digital Signal Analyzer 60 digitizes the signals
received from the Acoustic Receivers 40, 42 and 44 and performs
processing upon the resulting information in order to yield
accurate fluid level data. A High Resolution Digital Clock 70
resolution digital clock used for both signal generation and
analysis phases. A Data Storage Device 80 is employed to receive
and retrieve data.
[0049] In practice the distance from the acoustical transmitter
location (at the well head) to the fluid level in the bore below is
essentially the entire depth of the bore. Differences in this
distance correspond directly to changes in fluid level.
[0050] Referring to FIG. 2, a partial sectional view of a well head
system 120 is shown. The well head system 120 comprises a well
casing 160 as is known in the art. The well casing 160 is located
within the well bore (not shown). Within the well casing 160 is the
well tubing 170. The well tubing 170 extends downward in the well
casing 160 forming an annulus 180 between the outer surface of the
well tubing 170 and the inner surface of the well casing 160.
[0051] The well casing 160 is capped with a standard T-Head
connection 190. The T-Head connection 190 has two openings 192 and
194. One of the two openings 192 in the T-Head connection 190 is
utilized to remove, in the case of an oil and gas well, the oil and
gas through pipe 200. The second opening 194 is utilized to insert
various components of the present invention into an existing well
casing 160. Where the well is new the various components of the
present invention directly into the bore, or through the T-Head
connection 190.
[0052] Affixed to the well tubing 170 is the Acoustic Transmitters
30. The Acoustic Receiver 40 is affixed to the opposite side of the
well tubing 170. The choice of the location of the Acoustic
Receiver 40 is simply for convenience as it may also be affixed to
the inner surface of the T-Head connection 190. It is preferred
that Acoustic Receivers such as Acoustic Receiver 40 is directly
connected to the component to which the signal from the acoustical
receiver is delivered.
[0053] The second Acoustic Transmitter 32 is affixed to the outer
surface of the well casing 160. A second Acoustic Receiver 42 is
connected to the outer surface of the well casing 160.
[0054] The third Acoustic Transmitter 34 is attached to the inner
surface of the well casing 160. A third Acoustic Receiver 44 is
attached to the inner surface of the T-Head connection 190.
[0055] The present invention determines the fluid level 210 of the
well, whether, P2, P1, or P0, by determining the distance directly
or by harmonics according to well known equations. The present
invention operates to check each determination. For instance, the
well casing 160 is surrounded on its outer surface by voids, rock
strata, sand, water, petroleum, drilling cements and all other
manner of material found in and around a bore. The inner surface of
the well casing 160 is in contact with gases from the surrounding
formations and at the lower reaches of the bore of the well casing
160 is the fluid level 210. The inner surface of well casing 160 is
also subject over time to build up of paraffin, scale, and leakage
of elements from outside of the well casing 160.
[0056] The annulus 180 contains primarily gases and at the lower
reaches of the annulus 180 is the fluid level 210. The annulus 180
is also subject to the well tubing 170. The well tubing 170
contains primarily fluid at the lower reaches of the bore. At the
upper reaches of the bore. or below the residual liquid level in
the bore there is the potential for a build up of scale and
paraffin.
[0057] The fluid level 210 to be determined is thus subject to many
parameters, some predicable and some not. In short the various
conditions within the well casing 160, the well tubing 170 and the
the annulus 180 are dynamic.
[0058] In practice a electronic event originated at Digital Siganl
Generator 10 in FIG. 1 is fed to the Output Amplifier 20. From the
Output Amplifier 20, a series of Acoustic Transmitters 30, 32, and
34 converts the amplified electronic event to a sonic event.
[0059] In this example each of the Acoustic Transmitters 30, 32,
and 34 simultaneously and continuously emit a signal from their
respective positions according to FIG. 2. The sonic events from the
Acoustic Transmitters 30, 32, and 34 are reflected in the bore at a
time when the fluid level 210 is at P2. The reflected signals are
received by the Acoustic Receivers 40, 42 and 44. The
characteristics of each signal received by the Acoustic Receivers
40, 42 and 44 is fed to the Input Amplifier 50 to condition and
amplify each signal. The data for a P2 level is analyzed by the
Digital Signal Analyzer 60 and transmitted to the Data Storage
Device 80.
[0060] The well is then pumped to a well dry condition, which would
occur anyway for many wells, to obtain a P0 level. Each of the
Acoustic Transmitters 30, 32, and 34 simultaneously and
continuously emit a signal from their respective positions
according to FIG. 2. The sonic events from the Acoustic
Transmitters 30, 32, and 34 are reflected in the bore at a time
when the fluid level 210 is at P0. The reflected signals are
received by the Acoustic Receivers 40, 42 and 44. The
characteristics of each signal received by the Acoustic Receivers
40, 42 and 44 at the P0 level is fed to the Input Amplifier 50 to
condition and amplify each signal. The data for a P0 level is
analyzed by the Digital Signal Analyzer 60 and transmitted to the
Data Storage Device 80.
[0061] The well is then allowed to refill to an arbitrary level
between the P0 and P2 level. One or more further measurements are
taken as described above and are processed accordingly into the
Data Storage Device 80. From the foregoing data pump on and pump
off times may be set to minimize pumping time, minimize pumping
costs in energy and repair, and to maximize fluid output. In one
aspect of the invention the data generated can be utilized to
check, and recheck, components subject to the greatest ware and
abuse, e.g. the Acoustic Transmitters 30, 32, and 34; and the
Acoustic Receivers 40, 42 and 44. Well conditions down hole may be
analyzed by comparing recent data to stored data to determine, for
example, paraffin build up.
* * * * *