U.S. patent application number 17/006042 was filed with the patent office on 2022-03-03 for seismic assisted flooding processes for oil recovery in carbonates.
This patent application is currently assigned to SAUDI ARABIAN OIL COMPANY. The applicant listed for this patent is SAUDI ARABIAN OIL COMPANY. Invention is credited to Abdulaziz S. Al-Qasim, Subhash Ayirala, Ali Yousef.
Application Number | 20220065083 17/006042 |
Document ID | / |
Family ID | |
Filed Date | 2022-03-03 |
United States Patent
Application |
20220065083 |
Kind Code |
A1 |
Ayirala; Subhash ; et
al. |
March 3, 2022 |
SEISMIC ASSISTED FLOODING PROCESSES FOR OIL RECOVERY IN
CARBONATES
Abstract
An oil recovery method may include injecting 0.05 to 0.25 pore
volumes of low-salinity water having 4,000-8,000 ppm of total
dissolved solids into a reservoir, and then applying seismic
stimulation to the reservoir for a predetermined duration. The
steps of injecting low-salinity water and applying seismic
stimulation are repeated until 0.25 to 1.0 pore volumes of the
low-salinity water has been added to the reservoir. Then,
high-salinity water having 35,000 to 57,000 ppm of total dissolved
solids is introduced to the reservoir.
Inventors: |
Ayirala; Subhash; (Dhahran,
SA) ; Al-Qasim; Abdulaziz S.; (Dhahran, SA) ;
Yousef; Ali; (Dhahran, SA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SAUDI ARABIAN OIL COMPANY |
Dhahran |
|
SA |
|
|
Assignee: |
SAUDI ARABIAN OIL COMPANY
Dhahran
SA
|
Appl. No.: |
17/006042 |
Filed: |
August 28, 2020 |
International
Class: |
E21B 43/20 20060101
E21B043/20; C09K 8/58 20060101 C09K008/58; E21B 43/00 20060101
E21B043/00; E21B 49/00 20060101 E21B049/00 |
Claims
1. An oil recovery method comprising: (a) injecting 0.05 to 0.25
pore volumes of low-salinity water comprising 4,000-8,000 ppm of
total dissolved solids into a reservoir; (b) applying seismic
stimulation to the reservoir for a predetermined duration; (c)
repeating steps (a)-(b) until 0.25 to 1.0 pore volumes of the
low-salinity water has been added to the reservoir; and (d)
introducing an amount of high-salinity water comprising 35,000 to
57,000 ppm of total dissolved solids to the reservoir.
2. The method of claim 1, wherein the low-salinity water comprises
300-3000 ppm of sulfate ions, and 200-500 ppm of magnesium and
calcium ions.
3. The method of claim 1, wherein the low-salinity water comprises
an additive selected from the group consisting of polymers,
surfactants, carbonated water, nanoparticles, and combinations
thereof.
4. The method of claim 1, wherein the applying comprises repeatedly
releasing an amount of pressurized fluid into the reservoir at a
time interval of from 30 seconds to one minute.
5. The method of claim 4, wherein the pressurized fluid is
compressed at a pressure of from 2,500 to 5,000 psi.
6. The method of claim 4, wherein the amount of pressurized fluid
is from 5 to 10 gallons.
7. The method of claim 1, wherein the predetermined duration is
from 1 to 4 weeks.
8. The method of claim 1, wherein the seismic stimulation comprises
a frequency of from 20 Hz to 100 Hz.
9. The method of claim 1, wherein the amount of high salinity water
is from 0.5 to 1.0 pore volumes.
10. The method of claim 1, wherein the reservoir comprises an
injection well extending therethrough in which the injecting and
applying occur, wherein the injection well is horizontal or
vertical.
11. The method of claim 10, wherein the reservoir comprises at
least two injection wells in which the injecting and applying
occur.
12. The method of claim 1, wherein the reservoir comprises an
abandoned well in which the injecting and applying occur.
13. A method of determining seismic stimulation of a reservoir
comprising: (a) measuring at least one property of a reservoir; (b)
determining a seismic stimulation duration for the reservoir based
upon the at least one property of the reservoir. (c) injecting a
volume of low-salinity water comprising 4,000-8,000 ppm of total
dissolved solids into the reservoir; (d) applying seismic
stimulation to the reservoir for the determined seismic stimulation
duration determined by the determining; (e) repeating steps (c)-(d)
until 0.25 to 1.0 pore volumes of the low-salinity water has been
added to the reservoir; and (f) introducing an amount of
high-salinity water comprising 35,000 to 57,000 ppm of total
dissolved solids to the reservoir.
14. The method of claim 13, wherein the at least one property of
the reservoir is selected from the group consisting of rock
permeability, oil viscosity, number of injection wells, and
distance between a production well and an injection well.
15. The method of claim 13, wherein the determined seismic
stimulation duration is up to one week.
16. The method of claim 13, wherein the determined seismic
stimulation duration is from one week to two weeks.
17. The method of claim 13, wherein the determined seismic
stimulation duration is from two weeks to three weeks.
18. The method of claim 13, wherein the determined seismic
stimulation duration is from three weeks to four weeks.
Description
BACKGROUND
[0001] During primary oil recovery, oil inside an underground
hydrocarbon reservoir is driven to the surface (for example, toward
the surface of an oil well) by a pressure difference between the
reservoir and the surface. However, only a fraction of the oil in
an underground hydrocarbon reservoir can be extracted using primary
oil recovery. Thus, a variety of techniques for enhanced oil
recovery are utilized after primary oil recovery to increase the
production of hydrocarbons from an oil well. In enhanced oil
recovery, a fluid is typically introduced through an injection well
that is in fluid communication with the underground hydrocarbon
reservoir in order to re-pressurize the reservoir and displace oil
toward the surface. Some examples of these techniques include water
flooding, chemical flooding, and supercritical CO.sub.2 injections.
These techniques require the use of significant amounts of water
and/or other chemical constituents in order to effectively recover
oil from subterranean formations. They also may suffer from
inefficient oil recovery due to oil being dispersed in water
phases, making separation and recovery from a well challenging.
SUMMARY
[0002] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter.
[0003] In one aspect, embodiments disclosed herein relate to an oil
recovery method including injecting 0.05 to 0.25 pore volumes of
low-salinity water having 4,000-8,000 ppm of total dissolved solids
into a reservoir, and then applying seismic stimulation to the
reservoir for a predetermined duration. The steps of injecting
low-salinity water and applying seismic stimulation are repeated
until 0.25 to 1.0 pore volumes of the low-salinity water has been
added to the reservoir. Then, high-salinity water having 35,000 to
57,000 ppm of total dissolved solids is introduced to the
reservoir.
[0004] In another aspect, embodiments disclosed herein relate to an
oil recovery method including measuring at least one property of a
reservoir and then determining a seismic stimulation duration for
the reservoir based upon the reservoir property. The method also
includes injecting 0.05 to 0.25 pore volumes of low-salinity water
having 4,000-8,000 ppm of total dissolved solids into the reservoir
and then applying seismic stimulation to the reservoir for the
determined duration. The steps of injecting low-salinity water and
applying seismic stimulation are repeated until 0.25 to 1.0 pore
volumes of the low-salinity water has been added to the reservoir.
Then, high-salinity water having 35,000 to 57,000 ppm of total
dissolved solids is introduced to the reservoir.
[0005] Other aspects and advantages of the claimed subject matter
will be apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF DRAWINGS
[0006] FIG. 1 is a block flow diagram of a method in accordance
with one or more embodiments of the present disclosure.
[0007] FIG. 2A is a schematic depiction of oil in a reservoir in
accordance with one or more embodiments of the present
disclosure.
[0008] FIG. 2B is a schematic depiction of oil in a reservoir in
accordance with one or more embodiments of the present
disclosure.
[0009] FIG. 3 is a schematic depiction of oil in a reservoir in
accordance with one or more embodiments of the present
disclosure.
[0010] FIG. 4 is a schematic depiction of a seismic stimulation
tool in accordance with one or more embodiments of the present
disclosure.
[0011] FIG. 5 is a block flow diagram of a method in accordance
with one or more embodiments of the present disclosure.
DETAILED DESCRIPTION
[0012] Embodiments disclosed herein generally relate to the
enhanced oil recovery techniques that are directed to the
combination of a low salinity water injection coupled with seismic
stimulation. In particular, embodiments relate to alternating
injection of a low salinity water and application of seismic
stimulation until a threshold level of low salinity water is
injected, which is followed by injection of a high salinity
water.
[0013] In one aspect, embodiments disclosed herein relate to
injecting 0.05 to 0.25 pore volumes of low-salinity water
comprising 4,000-8,000 ppm of total dissolved solids into a
reservoir, applying seismic stimulation to the reservoir for a
predetermined duration, repeating the steps of injecting
low-salinity water and applying seismic stimulation until 0.25 to
1.0 pore volumes of the low-salinity water has been added to the
reservoir, and introducing an amount of high-salinity water
comprising 35,000 to 57,000 ppm of total dissolved solids to the
reservoir. Pore volume is defined as .PI.r2h*.phi., where r is the
radius (distance between the injection well to production well), h
is the reservoir thickness and .phi. is the porosity. Pore volume
may also be determined from numerical simulations as well as tracer
tests.
[0014] An exemplary method in accordance with one or more
embodiments of the present disclosure is shown in FIG. 1. First,
0.05 to 0.25 pore volumes of low-salinity water is injected into
reservoir (102). Then, seismic stimulation is applied to the
reservoir (104) for a predetermined duration of time. After seismic
stimulation has been applied for the predetermined duration of
time, low-salinity water is again injected into the reservoir (102)
and seismic stimulation is again applied to the reservoir (104).
These steps (102 and 104) are repeated sequentially until an amount
of 0.25 to 1.0 pore volumes of low-salinity water has been added to
the reservoir (106). Finally, high salinity water is introduced
into the reservoir (108).
[0015] Referring now to FIG. 2, a schematic depiction in accordance
with one or more embodiments of the present disclosure is shown.
FIGS. 2A and 2B show a mechanism of the effects of low-salinity
water injection. FIG. 2A shows a carbonate surface (204) with oil
(206) adhered to it. Carbonate surfaces (204) inside the reservoirs
described herein are typically oil-wet, and as a result, oil (206)
adheres strongly to the surfaces within the formation, making
extraction of that oil difficult. When injected into a reservoir,
the low salinity water (202) alters the wettability of carbonate
surfaces within the subterranean formation. The surface wettability
changes from oil-wet to water-wet, allowing the oil to detach from
the carbonate surface. The result of this change in wettability is
shown in FIG. 2B. The oil (206) detaches from the carbonate surface
(204) and is then suspended in the low-salinity water (202).
[0016] The low salinity water (202) may contain any appropriate
amount of total dissolved solids. In one or more embodiments, the
low-salinity water (202) contains 4,000-8,000 ppm total dissolved
solids. For example, the low salinity water (202) may have a lower
limit of any of 4,000, 4,500, or 5,000 total dissolved salts, and
an upper limit of any of 6,000, 7,000, or 8,000 total dissolved
salts, where any lower limit may be used in combination with any
mathematically compatible upper limit.
[0017] The low salinity water (202) may also include certain ions
that are beneficial for changing the wettability of surfaces within
the reservoir. For example, the low salinity water (202) may be
contain one or more salts that include but are not limited to
sodium chloride (NaCl), calcium chloride (CaCl.sub.2), magnesium
chloride (MgCl.sub.2), sodium sulfate (Na.sub.2SO.sub.4) calcium
sulfate (CaSO.sub.4) and magnesium sulfate (MgSO.sub.4). Thus,
embodiments of the disclosure may include aqueous solutions having
a concentration of one or more ions that include but are not
limited to sodium ions, sulfate ions, calcium ions, magnesium ions,
and chloride ions.
[0018] In one or more embodiments, the low-salinity water (202)
includes 300-3,000 ppm of sulfate ions. For example, the low
salinity water (202) may have a lower limit of any of 300, 500 or
700 ppm of sulfate ions, and an upper limit of any of 1,000, 2,000,
or 3,000 ppm of sulfate ions, where any lower limit may be used in
combination with any mathematically compatible upper limit. Without
being bound by any particular mechanism or theory, it is believed
negatively charged sulfate ions preferentially adsorb onto
positively charged carbonate surfaces, altering the positively
charged surface to a more negative charge. Negatively charged crude
oil functionality, such as carboxylic acids, may be adsorbed to the
carbonate surface. As a result of this wettability change due to
the presence of sulfate ions on the carbonate surface, crude oil
may be released from the carbonate surface, allowing for the oil to
be recovered.
[0019] In one or more embodiments, the low-salinity water (202)
includes 200-1,000 ppm of magnesium and calcium ions. For example,
the low salinity water (202) may have a lower limit of any of 200,
300 or 400 ppm of magnesium and calcium ions, and an upper limit of
any of 500, 750 or 1,000 ppm of magnesium and calcium ions, where
any lower limit may be used in combination with any mathematically
compatible upper limit. Without being bound by any particular
mechanism or theory, it is believed positively charged calcium ions
will also attract the negatively charged crude oil functionality,
such as carboxylic acids, which may help attract the crude oil away
from the carbonate surface, allowing for the oil to be
recovered.
[0020] The low-salinity water (202) may also contain additives. The
additives may be selected from the group consisting of polymers,
surfactants, carbonated water, nanoparticles, and combinations
thereof. In one or more embodiments, the low-salinity water
includes from 100 to 1,000 ppm of additives. Some additives, such
as surfactants and nanoparticles, may enhance the wettability
changes achieves by the previously-described ions present in
low-salinity water. Such additives may also reduce oil-water
interfacial tension by one to two orders of magnitude. Additives
such as polymers, may be employed to increase the viscosity of the
low-salinity water, improving mobility control.
[0021] In one or more embodiments, the amount of low-salinity water
(202) injected into the reservoir during each injection is from
0.05 to 0.25 pore volumes. For example, the amount injected into
the reservoir during each injection may have a lower limit of any
of 0.05, 0.08, 0.10, 0.12, or 0.16 pore volumes, and an upper limit
of any of 0.18, 0.20, 0.22, or 0.25 pore volumes, where any lower
limit may be used in combination with any mathematically compatible
upper limit.
[0022] The total amount of low-salinity water injected into the
reservoir is from 0.25 to 1.0 pore volumes. For example, the total
amount of low-salinity water may have a lower limit of any of 0.25,
0.28, or 0.50 pore volumes, and an upper limit of any of 0.6, 0.8,
or 1.0 pore volumes, where any lower limit may be used in
combination with any mathematically compatible upper limit. It is
envisioned that the particular pore volume of low salinity water
that is injected may depend, for example, based on the permeability
and reservoir heterogeneity, with greater volumes used in high
permeability and/or heterogeneous reservoirs.
[0023] As explained above, a result of the injection of low
salinity water is that the oil (204) is released from the carbonate
surface due to the change in wettability. Such tailored water
chemistry may favorably alter surface charges at carbonate/brine
and crude oil/brine interfaces to result in wettability
modifications towards water-wet conditions. The resulting water-wet
conditions would reduce the adhesion of crude oil to the carbonate
surfaces thereby releasing the oil attached to carbonate surface.
However, much of the oil released from the surface is then present
as droplets in the low-salinity water. This can be problematic for
efficient oil recovery because the oil phase has poor mobilization
within the water phase, and therefore the oil cannot be readily
recovered. In order to improve coalescence of the oil phase,
seismic stimulation (104) is applied to the reservoir to coalesce
and improve the connectivity of oil phase for improved
mobilization.
[0024] Turning now to FIG. 3, a schematic depiction of the effects
of seismic stimulation in accordance with one or more embodiments
of the present disclosure is shown. The seismic stimulation
(described in FIG. 1 as 102) (to be described in further detail
below) produces elastic waves (312) that propagate through the
reservoir. The elastic waves promote the coalescence of small oil
droplets (306) into larger oil ganglia/clusters (308). An oil
ganglion/cluster (308) may be from 10 to 100 times the size of an
oil droplet (306). For example, if an oil droplet has a diameter of
from 20-100 .mu.m, a ganglion/cluster may have a diameter of 2,000
to 10,000 p.m due to the seismic stimulation being applied. As the
seismic stimulation (102) is continuously applied over time, the
oil ganglia (308) are mobilized into an oil phase (310). This oil
phase (310) may then be more readily recovered from a production
well.
[0025] Seismic stimulation (102) is applied by releasing a small
amount of pressurized fluid into the reservoir. An exemplary
embodiment of an apparatus used for seismic stimulation is shown in
FIG. 4. The seismic stimulation apparatus (400) has three plungers
each having a corresponding barrel. The apparatus (400) has a
damper plunger (402), a damper barrel (404), an upper plunger
(406), an upper barrel (408), a lower plunger (410) and a lower
barrel (412). Specialized tubing (414) is located between the upper
(406) and lower (410) plungers, and serves as a compression
chamber. The lower plunger (410) contains a valve to bring in
fluids (not shown). The tool draws in fluid from the reservoir to
be compressed. Thus, the fluid used by the seismic stimulation
apparatus may be the previously-described low-salinity water. As
the pumping unit (416) reaches the bottom of a stroke, fluid is
drawn in through the valve, and into the specialized tubing (414),
where it is compressed between the upper (406) and lower (410)
plungers. The fluid may be compressed to a pressure of from 2,500
to 5,000 psi. The compressed fluid is released at the top of a
stroke of the pumping unit (416). Several gallons of fluid are
released during each stroke. The released fluid causes shock waves
that are amplified by an amplifier (418) located below the lower
plunger (410). The damper plunger (402) and barrel (404) decelerate
the upward velocity the apparatus experiences upon release of
fluid. As illustrating, the seismic stimulation apparatus (400) is
permanently installed in the injection well; however, it is also
envisioned that non-fixed tools may instead be used, which may be
run into the well on a wireline, for example. This fluid release
occurs at a consistent interval of from about 30 seconds to 1
minute in between each fluid release. The release of fluid creates
high energy elastic waves having 1-10 megawatts of power and a
frequency of from 20 Hz to 100 Hz.
[0026] The seismic stimulation may occur for a duration of 1-4
weeks, for example. In this time period, the oil coalesces to a
sufficient extent for recovery of the oil phase. The specific
amount of time for the seismic stimulation will be described in
greater detail below.
[0027] As shown above, the steps of injecting an amount of
low-salinity water as small slugs into the reservoir and applying
seismic stimulation are repeated until an amount of low-salinity
injected into the reservoir reaches a total amount of from 0.25 to
1.0 pore volumes. Repeatedly injecting small slugs of 0.05 to 0.25
pore volumes of low-salinity water releases additional oil droplets
from the carbonate surface. After each injection of low-salinity
water and subsequent release of oil droplets, the seismic
stimulation coalesces the oil droplets that were released to form
the coherent oil phase.
[0028] The final step of injecting high-salinity water in an amount
of 0.5 to 1.0 pore volumes serves to move the oil phase towards a
production well. The high-salinity water may contain 35,000 to
57,000 ppm of total dissolved solids. For example, the
high-salinity water may have a lower limit of any of 35,000,
37,000, or 40,000 total dissolved salts, and an upper limit of any
of 50,000, 52,000, 55,000, or 57,000 total dissolved salts, where
any lower limit may be used in combination with any mathematically
compatible upper limit. For example, it is understood that the
high-salinity water may be seawater, brackish water, produced
water, or other aqueous solutions having one or more salts present
therein. Salts that may be present include but are not limited to
alkali metal chlorides, hydroxides, or carboxylates. In some
embodiments, suitable salts may include sodium, calcium, cesium,
zinc, aluminum, magnesium, potassium, strontium, silicon, lithium,
chlorides, bromides, carbonates, iodides, chlorates, bromates,
formates, nitrates, sulfates, phosphates, oxides, fluorides and
combinations of these.
[0029] Turning now to FIG. 5, a method in accordance with one or
more embodiments of the present disclosure is shown. In the
embodiment shown in FIG. 5, at least one property of a reservoir is
measured (502). Then, based upon the measured property or
properties, a seismic stimulation duration is determined (504).
0.05 to 0.25 pore volumes of low-salinity water is injected into
reservoir (506). Then, seismic stimulation is applied to the
reservoir (508) for the determined duration of time. After seismic
stimulation has been applied for the determined duration of time,
low-salinity water is again injected into the reservoir and seismic
stimulation is again applied to the reservoir. These steps are
repeated sequentially until an amount of 0.25 to 1.0 pore volumes
of low-salinity water has been added to the reservoir (510). High
salinity water is then introduced into the reservoir (512).
Finally, displaced oil may be recovered from the carbonate
reservoir and produced through a production well.
[0030] The combined effect of the low salinity water injection
coupled with seismic stimulation is that a larger volume of oil is
released from rock surfaces (due to low salinity water effect
illustrated in FIG. 2) and then forms a larger oil bank due to the
increased oil phase connectivity (from the seismic stimulation
effect illustrated in FIG. 3). As a result of these two effects,
larger volumes of oil will be easily mobilized and pushed towards
the producing wells. Thus, advantageously, methods of the present
disclosure may provide for higher oil recovery, increased oil
production, lower water cut in the production and faster oil
recovery.
[0031] Embodiments of the present disclosure also relate to
designing a stimulation method for a given reservoir. As mentioned
above, a seismic stimulation duration of 1-4 weeks is described.
The particular duration may be based on viscosity of the oil,
formation permeability, and spacing between injection and
production wells, all of which may impact how the amount of time
needed for the oil to coalesce and begin to mobilize. For example,
lower viscosity oils, higher formation permeability and shorter
spacing between injection and production wells may utilize shorter
time periods for seismic stimulation. In contrast, high viscosity
oils, low permeability formations, and longer spacing between
injection and production wells may utilize greater time durations
for seismic stimulation.
[0032] The oil viscosity, the average permeability of targeted
reservoir zone, and the well spacing (i.e., the distance between
injection to production wells) may be used to determine the
duration of seismic stimulation. For example, if the oil viscosity
is less than 2.5 cP (centipoise) the seismic stimulation may be
performed for about one week. If the oil viscosity is from 2.5 to 5
cP, seismic stimulation may be performed for about 2 weeks. If the
oil viscosity if from 5 cP to 7.5 cP, seismic stimulation may be
performed for about 3 weeks. If the oil viscosity is from 7.5 cP to
10 cP, seismic stimulation may performed for about 4 weeks. If the
average permeability is less than 250 and (millidarcy), seismic
stimulation may be performed for about 4 weeks. If the average
permeability is from 250 to 500 md, seismic stimulation may be
performed for about 3 weeks. If the average permeability is from
500 to 750 md, seismic stimulation may be performed for about 2
weeks. If the average permeability is from 750 to 1000 md, seismic
stimulation may be performed for about 1 week. If the well spacing
is less than 250 m (meters), seismic stimulation may be performed
for about 1 week. If the well spacing is from 250 to 500 m, seismic
stimulation may be performed for about 2 weeks. If the well spacing
is from 500 m to 750 m, seismic stimulation maay be performed for
about 3 weeks. If the well spacing is from 750 m to 1000 m, seismic
stimulation may be performed for about 4 weeks. If measured
properties of a reservoir correspond to different seismic
stimulation durations, the longest duration may be selected.
[0033] Embodiments of the present disclosure may be useful for
applications in a variety of oil recovery operations, including in
a variety of rock formation types. It may be understood that when
formation types other than carbonates are encountered, that the
salinity of the fluids may be altered based on ion exchange sites
present at rock surface so that a change in wettability may be
achieved. Further, the methods described herein are suitable for
either vertical or horizontal wells. The methods described herein
may be suitable for use at single injection wells or multiple
injection wells. If multiple injection wells are used, the methods
described herein may be performed at each individual well according
to the methods described above. The methods may also be used in
abandoned wells that are in close proximity to active wells.
[0034] Embodiments of the present disclosure may provide at least
one of the following advantages. The methods disclosed herein may
result in in higher oil recovery, increased oil production, lower
water cut in production and faster oil recovery as compared to
traditional methods.
[0035] Although only a few example embodiments have been described
in detail above, those skilled in the art will readily appreciate
that many modifications are possible in the example embodiments
without materially departing from this invention. Accordingly, all
such modifications are intended to be included within the scope of
this disclosure as defined in the following claims. In the claims,
means-plus-function clauses are intended to cover the structures
described herein as performing the recited function and not only
structural equivalents, but also equivalent structures. Thus,
although a nail and a screw may not be structural equivalents in
that a nail employs a cylindrical surface to secure wooden parts
together, whereas a screw employs a helical surface, in the
environment of fastening wooden parts, a nail and a screw may be
equivalent structures. It is the express intention of the applicant
not to invoke 35 U.S.C. .sctn. 112 (f) for any limitations of any
of the claims herein, except for those in which the claim expressly
uses the words `means for` together with an associated
function.
* * * * *