U.S. patent application number 13/832759 was filed with the patent office on 2014-01-30 for fracture water treatment method and system.
Invention is credited to Joseph G. Munisteri.
Application Number | 20140027386 13/832759 |
Document ID | / |
Family ID | 49993844 |
Filed Date | 2014-01-30 |
United States Patent
Application |
20140027386 |
Kind Code |
A1 |
Munisteri; Joseph G. |
January 30, 2014 |
Fracture Water Treatment Method and System
Abstract
A method and system for treatment of flow-back and produced
water from a hydrocarbon well in which fracturing operations are
carried out using a phase separation and creating of positive
charge in the water.
Inventors: |
Munisteri; Joseph G.;
(Houston, TX) |
Family ID: |
49993844 |
Appl. No.: |
13/832759 |
Filed: |
March 15, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13594497 |
Aug 24, 2012 |
8424784 |
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13832759 |
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61676628 |
Jul 27, 2012 |
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Current U.S.
Class: |
210/744 ;
210/243; 210/513; 210/748.01; 210/97 |
Current CPC
Class: |
B01D 21/10 20130101;
C02F 2101/32 20130101; C02F 2209/42 20130101; E21B 43/34 20130101;
C02F 2201/483 20130101; B01D 17/0214 20130101; B01D 19/00 20130101;
B01D 21/0009 20130101; B01D 19/0063 20130101; C02F 1/487 20130101;
C02F 2209/005 20130101; C02F 1/008 20130101; B01D 17/04 20130101;
C02F 1/484 20130101; B01D 17/12 20130101; C02F 2103/10 20130101;
C02F 2209/02 20130101; B01D 19/0068 20130101; B01D 21/34 20130101;
C02F 2103/06 20130101; E21B 43/26 20130101; B01D 21/2494 20130101;
B01D 21/24 20130101; E21B 21/065 20130101; B01D 17/0208 20130101;
E21B 43/267 20130101 |
Class at
Publication: |
210/744 ;
210/748.01; 210/243; 210/97; 210/513 |
International
Class: |
C02F 1/00 20060101
C02F001/00; B01D 21/34 20060101 B01D021/34; B01D 19/00 20060101
B01D019/00 |
Foreign Application Data
Date |
Code |
Application Number |
Aug 24, 2012 |
US |
PCTUS/1327429 |
Claims
1. A system for treating hydrocarbon well fracture water from a
hydrocarbon well, a system comprising: means for separating solids
from fracture water, wherein a flow of water with suspended solids
results; means for separating the flow of water into a plurality of
flows of water; means for generating positive charge in the
plurality of flows of water, wherein a plurality of flows of
positively-charged water results; and means for comingling
plurality of flows of positively-charged water.
2. A system as in claim 1, wherein said means for separating
comprises a three-phase, four material separator.
3. A system as in claim 2, wherein said means for separating
further comprises a second two phase separator, the two-phase
separator comprising an input for receiving water flow from the
three-phase gas oil separator, and an output for the flow of water
with suspended solids.
4. A system as in claim 2, further comprising: means for monitoring
an oil/water interface level; and means for controlling the
oil/water interface level in the first and second separator.
5. A system as in claim 4 wherein said means for monitoring
comprises an oil/water interface level indicator and control valve
sensor.
6. A system as in claim 4 wherein said means for controlling
comprises a cascade control system.
7. A system as in claim 1, wherein the means for separating the
flow of water into a plurality of flows of water comprises a
manifold having an input port to receive the flow of water with
suspended solids and a plurality of output ports, each of which has
a cross-sectional area that is smaller than the cross-sectional
area of the input of the manifold; and wherein the sum of the
cross-sectional areas of the output ports is greater than the
cross-sectional area of the input ports, whereby the flow rate
exiting the manifold is less than the flow rate entering the
manifold.
8. A system as in claim 7 wherein the manifold comprises a 1:12
manifold.
9. A system as in claim 1, wherein the means for separating the
flow of water into a plurality of flows of water comprises a water
truck having a plurality of compartments, each compartment being
positioned to receive a portion of the flow of water.
10. A system as in claim 1, wherein said means for generating
positive charge comprises means for treating each of the plurality
of flows of water with electromagnetic flux.
11. A system as in claim 10, wherein the means for treating each of
the plurality of flows of water with electromagnetic flux
comprises: a pipe; and at least one electrical coil having an axis
substantially coaxial with the pipe.
12. A system as in claim 11 wherein said pipe consists essentially
of non-conducting material.
13. A system as in claim 11 wherein said pipe consists essentially
of stainless steel.
14. A system as in claim 11 flirther comprising a ringing current
switching circuit connected to the coil.
15. A system as in claim 14 wherein said ringing current switching
circuit operates in a fullwave mode.
16. A system as in claim 14 wherein said ringing circuit has a
frequency between about 10 kHz to about 80 kHz.
17. A system as in claim 1, wherein said means for co-mingling
comprises a manifold having input ports for a plurality of flows of
positively-charged water and an output port.
18. A system as in claim 17 wherein said means for co-mingling
further comprises a well fracturing water and proppant blender.
19. A system as in claim 1 wherein the majority of the suspended
solids are less than about 100 microns.
20. A system as in claim 19 wherein substantially all the suspended
solids are less than about 100 microns.
21. A system as in claim 20 wherein the majority of the suspended
solids are less than about 10 microns.
22. A system as in claim 21 wherein substantially all the suspended
solids are less than about 10 microns.
23. A system as in claim 1 wherein said means for separating
comprises a two-stage separator.
24. A system as in claim 23 wherein said two-stage separator
comprises: a three-phase separator having a water output coupled to
an input of a two-phase separator.
25. A system as in claim 24 wherein said three-phase separator
comprises a four-material separator having at least four outputs
including: a slurry, water having suspended solids therein,
hydrocarbon liquid, and hydrocarbon gas.
26. A method of treating hydrocarbon well fracture water from a
hydrocarbon well, said method comprising: separating solids from
fracture water, wherein a flow of water with suspended solids
results; separating the flow of water into a plurality of flows of
water; generating positive charge in the plurality of flows of
water, wherein a plurality of flows of positively-charged water
results; comingling the plurality of flows of positively-charged
water after said generating.
27. A method as in claim 26, further comprising: monitoring an
oil/water interface level and controlling the oil/water interface
level in the separator.
28. A method as in claim 26, further comprising slowing the flow
rate in the plurality of flows of water to be less than the flow
rate of the flow of water with suspended solids.
29. A method as in claim 26, wherein said generating positive
charge in the flows of water comprises treating each of the
plurality of flows of water with electromagnetic flux.
30. A method as in claim 26, wherein the majority of the suspended
solids are less than about 100 microns.
31. A method as in claim 30, wherein substantially all the
suspended solids are less than about 100 microns.
32. A method as in claim 30, wherein the majority of the suspended
solids are less than about 10 microns.
33. A method as in claim 32, wherein substantially all the
suspended solids are less than about 10 microns.
34. A method as in claim 26, wherein said separating comprises
two-stage separating.
35. A method as in claim 34, wherein said two-stage separating
comprises: passing the fracture water through a three-phase
separator, wherein a water output from the three-phase separator
results, and passing the water output from the three-phase
separator through a two-phase separator.
36. A method as in claim 35, wherein said three-phase separator
comprises a four-material separator having at least four outputs
including: a slurry, water having suspended solids therein,
hydrocarbon liquid, and hydrocarbon gas.
37. A system for treating hydrocarbon well fracture water from a
hydrocarbon well, a system comprising: means for separating solids
from fracture water, wherein a flow of water with suspended solids
results; means for separating the flow of water into a plurality of
flows of water; means for generating positive charge in the
plurality of flows of water, wherein a plurality of flows of
positively-charged water results; and means for comingling
plurality of flows of positively-charged water.
38. A system as in claim 37, wherein said means for separating
comprises a three-phase, four material separator.
39. A system as in claim 38, wherein said means for separating
further comprises a second two phase separator, the two-phase
separator comprising an input for receiving water flow from the
three-phase gas oil separator, and an output for the flow of water
with suspended solids.
40. A system as in claim 38, further comprising: means for
monitoring an oil/water interface level; and means for controlling
the oil/water interface level in the first and second
separator.
41. A system as in claim 40, wherein said means for monitoring
comprises an oil/water interface level indicator and control valve
sensor.
42. A system as in claim 40, wherein said means for controlling
comprises a cascade control system.
43. A system as in claim 37, wherein the means for separating the
flow of water into a plurality of flows of water comprises a
manifold having an input port to receive the flow of water with
suspended solids and a plurality of output ports, each of which has
a cross-sectional area that is smaller than the cross-sectional
area of the input of the manifold; and wherein the sum of the
cross-sectional areas of the output ports is greater than the
cross-sectional area of the input ports, whereby the flow rate
exiting the manifold is less than the flow rate entering the
manifold.
44. A system as in claim 43, wherein the manifold comprises a 1:12
manifold.
45. A system as in claim 37, wherein the means for separating the
flow of water into a plurality of flows of water comprises a water
truck having a plurality of compartments, each compartment being
positioned to receive a portion of the flow of water.
46. A system as in claim 37, wherein said means for generating
positive charge comprises means for treating each of the plurality
of flows of water with electromagnetic flux.
47. A system as in claim 46, wherein the means for treating each of
the plurality of flows of water with electromagnetic flux
comprises: a pipe; and at least one electrical coil having an axis
substantially coaxial with the pipe.
48. A system as in claim 47, wherein said pipe consists essentially
of non-conducting material.
49. A system as in claim 47, wherein said pipe consists essentially
of stainless steel.
50. A system as in claim 47, further comprising a ringing current
switching circuit connected to the coil.
51. A system as in claim 50, wherein said ringing current switching
circuit operates in a full-wave mode.
52. A system as in claim 50, wherein said ringing circuit has a
frequency between about 10 kHz to about 80 kHz.
53. A system as in claim 37, wherein said means for co-mingling
comprises a manifold having input ports for a plurality of flows of
positively-charged water and an output port.
54. A system as in claim 53, wherein said means for co-mingling
further comprises a well fracturing water and proppant blender.
55. A system as in claim 37, wherein the majority of the suspended
solids are less than about 100 microns.
56. A system as in claim 55, wherein substantially all the
suspended solids are less than about 100 microns.
57. A system as in claim 56, wherein the majority of the suspended
solids are less than about 10 microns.
58. A system as in claim 57, wherein substantially all the
suspended solids are less than about 10 microns.
59. A system as in claim 37, wherein said means for separating
comprises a two-stage separator.
60. A system as in claim 59, wherein said two-stage separator
comprises: a three-phase separator having a water output coupled to
an input of a two-phase separator.
61. A system as in claim 60, wherein said three-phase separator
comprises a four-material separator having at least four outputs
including: a slurry, water having suspended solids therein,
hydrocarbon liquid, and hydrocarbon gas.
62. A system for treatment of hydrocarbon well fracture water, the
system comprising: a multi-phase separator; a manifold having an
input port connected to an output of the multiphase separator and
having multiple output ports; a plurality of pipes, each having
coils wound on the pipe, wherein each pipe has an input end
connected to an output port of the manifold and each pipe has an
output end; a co-mingling manifold having input ports connected to
the output ends of the plurality of pipes.
63. A system as in claim 62, further comprising a proppant-water
blender connected to an output of the co-mingling manifold.
64. A system as in claim 62, wherein the multi-phase separator
comprises a multi-stage separator.
65. A system as in claim 64, wherein the multi-stage separator
comprises a two-stage separator, wherein: a first stage of the
two-stage separator comprises a three-phase separator and a second
stage of the two-stage separator comprises a two-phase
separator.
66. A system as in claim 65, wherein the three-phase separator
comprises a four-material separator.
67. A system as in claim 66, wherein the four-material separator
comprises an oil-water interface control system.
68. A method of controlling of water/liquid hydrocarbon interface
in a three-phase separator, the method comprising: establishing a
water/liquid hydrocarbon interface in a three-phase separator;
measuring the water/liquid hydrocarbon interface in the three-phase
separator, wherein a water/liquid hydrocarbon interface measurement
signal results; comparing the water/liquid hydrocarbon interface
measurement signal to a set point, wherein a comparison signal
results; reducing the flow-back or produced water into the
three-phase separator of hydrocarbon well fracture water when the
comparison signal indicates the water/liquid hydrocarbon interface
is above the set point; and increasing flow into the three-phase
separator when the comparison signal indicates the water/liquid
hydrocarbon interface is below the set point, wherein the
increasing flow comprises hydrocarbon well fracture water from a
well and make-up water from a storage tank or a lagoon.
69. A method as in claim 68, further comprising: decreasing the
flow exiting the three-phase separator at the same rate in balance
with the flow as it decreases into the three-phase separator, and
increasing the flow exiting the three-phase separator at the same
balanced rate as the flow increases into the three-phase
separator.
70. A system for controlling of water/liquid hydrocarbon interface
in the three-phase separator, a method comprising: means for
establishing a water/liquid hydrocarbon interface in a three-phase
separator; means for measuring the water/liquid hydrocarbon
interface in the three-phase separator, wherein a water/liquid
hydrocarbon interface measurement signal results; means for
comparing the water/liquid hydrocarbon interface measurement signal
to a set point, wherein a comparison signal results; means for
reducing the flow into the three-phase separator of hydrocarbon
well fracture water when the comparison signal indicates the
water/liquid hydrocarbon interface is above the set point and for
increasing flow into the three-phase separator when the comparison
signal indicates the water/liquid hydrocarbon interface is below
the set point, wherein the increasing flow comprises hydrocarbon
well fracture water from and make-up water.
71. A system as in claim 70, wherein said means for establishing a
water/liquid hydrocarbon interface comprises a diaphragm wier.
72. A system as in claim 70, wherein said means for measuring the
water/liquid hydrocarbon interface comprises a liquid level
indicator controller-type sensor.
73. A system as in claim 70, wherein said means for comparing the
water/liquid hydrocarbon interface measurement signal to a set
point comprises a continuous capacitance level transmitter.
74. A system as in claim 70, wherein said means for reducing and
for increasing the flow into the three-phase separator comprises a
turbine type flow meter and an inlet type control valve in-line
with the input of the three-phase separator.
75. A system as in claim 70, further comprising: means for
decreasing and balancing the flow exiting the three-phase separator
at the same rate as the flow decreases into the three-phase
separator and for increasing the flow exiting the three-phase
separator at the same balanced rate as the flow increases into the
three-phase separator.
76. A system as in claim 75, wherein said means for decreasing and
increasing the flow exiting the three-phase separator comprises an
orifice-type flow meter connected in-line with the water output of
the three-phase separator.
77. A system as in claim 75, wherein said means for decreasing and
increasing the flow exiting the three-phase separator comprises an
orifice-type flow controller controlling the water output of the
three-phase separator.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation in part of U.S.
application Ser. No. 13/594,497 filed Aug. 24, 2012, which claims
priority to U.S. Provisional App. No. 61/676,628, filed Jul. 27,
2012. This application also claims priority to U.S. Divisional
application Ser. No. 13/753,310, filed on Jan. 29, 2013.
BACKGROUND OF THE INVENTION
[0002] This invention concerns the apparatus and processing steps
for treating the flow-back and produced water and the other
constituents that are used to hydraulically cause the creation of
channels or fractures or fissures in hydrocarbon wells (for
example, deep oil-shale deposits).
[0003] Over the centuries, people have tried different ways to take
advantage of and use the inherent qualities of naturally-occurring
hydrocarbon compounds to enhance his life style and cope with the
many challenges of existence. For over two thousand years, the
"Burning Sands" of Kirkuk, in Iraq, provided heat to Kurdish
tribes, which came from the methane gas that seeped upwards from
deep Geological formations to the Earth's surface only to be
ignited and burn continuously to this day. Also the surface
seepages of crude oil, in Pennsylvania and California, were used by
the American Indians to water-proof the canoes that they used in
traveling on the waterways of North America. These are only two
early examples of man's utilization of natural gas and crude oil to
improve his way of life.
[0004] Drake's successful drilling of a shallow crude oil well in
Pennsylvania, in the late Nineteenth Century, marked the beginning
of man's greatest period of economic growth driven, in great
measure, by the rapid strides that were made in the exploration,
production, and refining, of naturally-occurring gaseous and liquid
hydrocarbon compounds. They are now used for transportation fuels,
power generation, lubricants, petrochemicals, and the many
thousands of other products and applications that we use in our
daily lives today. The birth and development of what we now call
"the Oil Industry" is one of the major principal factors and
enabling driving forces contributing to the establishment and
spectacular growth in the world's economy. This period of economic
development is known as "The Industrial Revolution."
[0005] During this period, many new oil fields were discovered in
many parts of the world and the growth in the demand for crude oil
and petroleum products grew at a fantastic rate due to the many new
uses for petroleum-derived products that continued to be discovered
well into the Twenty-First Century. Throughout this period the Oil
Industry found many oil new fields or large deposits or reservoirs
of conventionally varying hydrocarbon mixtures of liquid and
gaseous compounds (both on land and offshore in the various bodies
of water throughout the world). At the same time, the Industry also
discovered the existence of large quantities of heavy and light
hydrocarbon compound mixtures that were nonconventional in
structure and were so enmeshed in the complex material matrixes
that the hydrocarbon molecule compounds contained therein could not
be extracted economically.
[0006] These nonconventional hydrocarbon compound sources fall into
two distinctly different categories. Firstly there are the "heavy"
or long-chain hydrocarbon molecule compounds such as the oil sands
deposits in Canada and the heavy oil deposits in the Kern River or
Bellridge regions of California or in the heavy oil belt of the
Orinoco river delta region in Venezuela or the Mayan oil in Mexico
where the heavy oil produced was extremely viscous and was in a
semi-solid state at ambient temperatures. In these cases pour point
or viscosity reduction was of primary importance. Secondly there
are the "light" or "short-chain" hydrocarbon molecule compounds
that are entrapped in various shale deposits throughout the United
States and in many other areas in the world.
[0007] In certain countries of the world, namely in Spain, Estonia
and Brazil there are large, but shallow, oil shale deposits where
those countries did not have large reserves or deposits of
conventional crude oil. There, a "brute force" method for the
extraction of shale oil or kerogen was carried out by heating the
shale rock in high temperature pressurized retorts. This practice
was started as early as the nineteen twenties. The extracted
kerogen or shale oil fuel was then burned in furnaces for heating
purposes as well as a transportation fuel for diesel and other
internal combustion engines. The extracted kerogen fuel had about
the same b.t.u. fuel value and combustion characteristics as
regular-grade gasoline or petrol as produced from conventional
crude oil refining facilities. Those countries also did not have
the necessary amount of hard currency or United States Dollars to
buy conventional crude oil on the international commodities market
but they did have large volumes of shale rock (although the amount
of shale oil or Kerogen extracted from these shale deposits was
less than four percent by weight of the shale rock itself, leaving
about ninety five percent of the shale rock as waste materials).
The hot condensable hydrocarbon compounds were liquefied in a
conventional condensing heat exchanger unit and became the kerogen
fuel. The non-condensable hydrocarbons, mainly methane, were flared
or just released into the atmosphere. All these short-chain or
light hydrocarbon compounds are trapped or sealed within the oil
shale material matrix structure and when heated, under pressure,
they are released or liberated from this matrix in a gaseous
phase.
[0008] In the United States, there are many areas where oil shale
rock deposits are to be found, but most of them are located as deep
deposits five to ten thousand feet below the surface of the earth.
As early as before the nineteen twenties, many attempts made to
mine or extract the kerogen oil from stratified shale formations.
Although the shale oil proved to be a very suitable hydrocarbon
product, its cost of production was well in excess of the market
price of similar products; thus this situation proved to be
uneconomical. Additional development and investment was not
justified at that time.
[0009] All of these factors and conditions have changed
dramatically over the past years due, primarily, to the rapid
development and exploitation of two specialized technologies. The
first of these is the carefully controlled and steerable
directional drilling techniques that allowed rigs to be able to
initially drill vertically and then be controlled or steered to
rotate into a horizontal position while drilling to a
pre-determined depth. The drilling could then continue to drill
well bores horizontally in the shale formation for a considerable
distance. The second most important technological development was
the application of an old process, namely the practice of
hydraulically fracturing older vertical oil wells in order to
increase the flow rate as well as to promote the further
stimulation of the older, oil wells and thereby extend the economic
life of the depleting oil fields.
[0010] Over the years many different techniques were developed and
implemented in an attempt to extend the productive life of older
oil and more mature oil field fields. Water flooding was one of the
practices that was employed to maintain reservoir pool pressure in
depleting oil fields as well as the injection of pressurized
methane gas (when available and not being flared) in order to
achieve the same result. Another technique that was tried was the
use of "Shaped Charges" of explosives that were strategically
placed in well casings so they could be detonated in the pay zone
areas in the well bore and the force of these explosions penetrated
the wall of the casing and caused fractures or fissures to be
opened.
[0011] Such methods for EOR (Enhanced Oil Recovery) were the oil
industry norm for many years. However some oil companies were
concerned about the dangers in using explosives as a means of
extending the productive life of depleting oil fields; and, in the
late nineteen forties, the practice of using highly-pressured water
and sand mixtures to produce fissures or fractures in the pay-zone
areas began. This technique was developed to try to increase the
rate of flow in the oil well and also to extend the productive life
of a mature and depleting oil field without the use of explosives.
Opening new channels hydraulically in the older pay zones made it
easier for the liquid and gaseous hydrocarbons to flow freely under
bottom hole pressure up to the surface for collection as crude oil
and gas products.
[0012] Also the practice of using work-over rigs to clean out old
oil well casings that had restricted hydrocarbon flows due to the
accumulation of asphaltic or paraffinic compounds was wide-spread
during this period.
[0013] The use of all these types of oil well stimulation
practices, as well as the use of other enhanced oil recovery
techniques, continued over a long period of time and many
improvements were developed over the years. One of these
improvements was the development of the larger capacity and more
powerful barite mud pumps that were needed to assist in the
drilling of deeper and deeper oil wells, both onshore as well as
offshore. Some of these oil wells were drilled in water depths
exceeding eight thousand feet; further drilling depths adding more
than twenty thousand feet, and thus there was a need to enlarge the
capacity and increase the pressure capability level of the
hydraulic fracturing pumps as well.
[0014] The discovery of a number of large deposits of oil shale
formations, plus the newly developed technologies of steerable
directional drilling capabilities, coupled with the ability to use
highly pressurized hydraulic fracturing equipment, allowed the
industry to proceed with these new fracturing techniques. They were
able to directionally drill, both vertically and horizontally, in
the deep shale formations and then hydraulically fracture the
formation to release the gaseous and liquid hydrocarbons that were
contained in the shale matrix material formations. These new
technologies have caused an economic "sea change" in how the world
now values liquid and gaseous hydrocarbons in the global energy
commodities market.
[0015] However, during the period when the application of hydraulic
fracturing was becoming more wide spread, its growth,
technologically and operationally, was carried out in a very
haphazard, hit and miss, ad hoc manner. Many of the improvements
that were made were the result of unscientifically developed trial
and error attempts to improve the rate of production in an oil well
as well as trying to extend the economic life of established oil
fields. This was all done without the benefit of fully examining or
understanding the sound scientific reasons behind the need for
those improvements. The best example of this unscientific approach,
in trying to solve specific processing problems, is what was
occurring in the proper selection and use of various types of
proppants in the hydraulic fracturing process.
[0016] After the initial pressurized water fracturing is
accomplished, strong proppant materials need to remain in the
fissures or fractures that are produced by the pressurized water
technique if the desired increase in the flow rate of the produced
hydrocarbons is to be achieved. Proppants are the selected means of
"propping up" the new openings or cracks in the formations, so that
they will continue to keep the new fractures or fissures open and
to allow the hydrocarbon compounds to flow freely into the well
bores so they can be discharged through the well head's control
equipment.
[0017] Without the proper proppants that are strong enough and
correctly sized to keep the fissures continuously open, the well's
production rate will decline rapidly as proppant fines and softer
material particles fill up the fissures. These will decrease the
rate of flow and ultimately block the flow of hydrocarbons into the
well bore. Many types of sands having different compositions,
shapes and sizes were tested as well as many other types of
proppant materials such as aluminum oxides, etc.
[0018] The key issue here is that the proper proppant that should
be used in a hydraulic fracturing process is the single most
important factor that is needed in achieving and maintaining the
proper "voids ratio" that is needed in the pressurized water
fractured channels to be able to realize the full benefit of the
hydraulic fracturing process.
[0019] While these considerations are important in hydraulic
fracturing in vertically drilled oil wells with selected pay zones,
they are far more critical and important when applying the
hydraulic fracturing process in horizontally-layered oil shale
formations. As a result of the magnitude of the "Shale Gas
Revolution" we are now just starting to learn more and understand
more about the nature and characteristics of the various types of
shale formations.
[0020] Oil shale is a form of sedimentary deposits that were laid
down eons ago in the form mainly of calcium carbonates, sodium
carbonates, calcium bicarbonates, quartz as well as soil materials
and other compounds that became entrapped in the matrix of
materials as these oil shales were being formed and ultimately
deposited in the shale formations that we know about today. Many
oil shale formations cross tectonic fault lines in the crust of the
earth and thus can be discontinuous in their configuration. Some
oil shale formations are slightly inclined in both the vertical and
horizontal planes. As a result, wire line tracking as well as three
dimensional seismic analyses becomes an important part of the shale
gas exploration and development process.
[0021] Retrospectively it is important to recognize and stress the
critical function that properly structured and sized proppants
perform for the optimum extraction and production of gaseous and
liquid hydrocarbon compounds which are the product as a result of
the hydraulic fracturing of an oil shale deposit. This fact was not
fully understood or appreciated, in the oil industry, until early
in the twenty-first century. By the end of the twentieth century
the Petroleum Industry had already been using the technique of
hydraulic fracturing for enhanced oil recovery and oil well
stimulation on producing wells for more than fifty years. All of
the hydraulic fracturing operations that were carried out before
the turn of the twenty first century were designed to extend the
productive life of existing vertically drilled oil wells or achieve
greater hydrocarbon flow rates for completed wells. All of these
hydraulic fracturing operations were carried out in
vertically-drilled oil wells and were fracturing pay zones that
were essentially sand in composition, and were producing flowing
liquid or gaseous hydrocarbons under bottom hole temperature and
pressure conditions. All were in sand formations that had
relatively high permeability and porosity values or good
voids-ratio characteristics.
[0022] With the introduction of steerable vertical and horizontal
drilling equipment together with very high pressure fracturing
pumps (called by some "intensifiers"), the oil industry then
applied the same hydraulic fracturing techniques that had been
successfully developed and used in vertical oil well hydraulic
fracturing operations and applied these same procedures to the well
bores that were horizontally drilled in the deep shale formations
but with less than satisfactory results. Some of the oil shale
formations were more productive than others and a large number of
approaches were attempted in order to try to increase the amount of
encapsulated hydrocarbons that were released by hydraulic
fracturing. Chemicals were added to try to control the growth of
the water borne microorganisms that were impeding the flow of
hydrocarbons, chemicals were also added in order to control
corrosion and encrustations. Surface tension reducing chemicals
were also added to try to make the fracturing water more capable of
penetrating the fissures that were created by the highly pressured
water. Some combination of steps were more successful in one area
of oil shale than the same steps being taken and applied in another
oil shale formation particularly in the difference in the
percentage or amount of hydrocarbon product that was ultimately
being extracted from a specific amount of hydrocarbon content in a
given oil shale deposit.
[0023] It was not until the industry started to realize that the
traditional principles of petroleum technology were not fully
applicable to the newly developed attempts to extract entrapped
liquid and gaseous hydrocarbons from mineral rock formations that
did allow them to flow freely even in deep high temperature and
high pressure locations. Petroleum engineers then turned to the
principles of applying the examination of hard rock mechanics of
minerals geology criteria in seeking a comprehensive analysis and
understandable answer to these issues. Recently, research efforts
proved that all shale formations could be categorized and could be
roughly divided in to two distinct measurable and identifiable
classifications being either a "soft shale" or a "hard shale." See,
e.g. Denney, Dennis. (2012 March). Fracturing-Fluid Effects on
Shale and Proppant Embedment. JPT. pp. 59-61. The test criteria are
based upon the principle of measuring the stress/strain or Young's
Modulus value of a given material both before and after fracturing.
The test measures the nano indentation of a mineral after applying
a specific stress level. Hard shales recorded low nano indentation
values while the soft shales tested measured higher indentation
values. The hard shales had mainly silica, calcium carbonates,
calcites, and quartz in their composition along with colloidal
clays; whereas the soft shales had sodium bicarbonates, nahcolites
and colloidal clay components.
[0024] The ability to accurately determine the true mineral
characteristics of an oil shale is very important in selecting the
best operational techniques that are needed in order to optimize or
maximize the ultimate recovery of hydrocarbon components from a
specific shale formation or deposit. Soft oil shale formations
respond differently from hard oil shale formations after both have
been subjected to the same level of hydraulic water pressure for
the same soaking period of time. Hard oil shales, under high
hydraulic pressures yield fissures or channels that are relatively
short in penetration length and rather small in the cross sectional
diameters of their fissures or flow channels. Soft oil shales, on
the other hand, under the same high hydraulic pressure and soaking
period yield fissures that are of greater length and have cross
sectional diameters that are relatively larger than what can be
achieved from the hydraulic fracturing of materials in the hard oil
shale formations.
[0025] Aside from controlling the growth of microorganisms and the
prevention of scale encrustations and "slick" water provisions, the
most important factor in an operation's ability to extract the
maximum or optimum amount of hydrocarbon from a given shale
formation is the selection of the proper size and type of proppant
that is carried into the fracture zone by the fracturing water. If
the shale to be fractured is a hard shale the proppant must be of
small enough size so that it can be carried into the small diameter
fissures that are the result of the hard shale fracturing operation
and strong enough to be able to keep the channel or fissure open
long enough in order to allow the contained liquid or gaseous
hydrocarbon product to flow freely horizontally and vertically in
the well bore so as to be recoverable after being released to the
surface facilities. If the proppant used is too large for the small
diameter size fissure, the proppant will not penetrate into the
fissure and remain there in order to keep the fissure channel open,
and the amount of recoverable produced hydrocarbons will be
significantly reduced. Alternatively, if an operation is hydraulic
fracturing in a soft shale formation the properly sized proppant
should be larger in diameter than the proppant that would be
suitable for use in a hard shale. This will allow the proppant to
be carried into the larger diameter fissures that are the result of
the hydraulic fracturing of a soft shale. A smaller size proppant
would not be as effective and this would result in a significant
reduction in the amount of hydrocarbon product that could be
produced.
[0026] Now that we have more scientifically measureable data
regarding the differences in the various types of oil shale
formations the industry now realizes, more clearly, the economic
importance of selecting the proper proppant for the hydraulic
fracturing of various types of oil shale formations. The best
proppant for hydraulically fracturing soft mineral shales we now
know is different from the best proppant that we need to use when
hydraulically fracturing a hard mineral shale. Thus, there is a
need for specific proppants for specific oil shales.
[0027] An object of examples of the invention, therefore, is to
provide a wide range of properly sized and constituted proppants
using virtually all the slurry materials that are carried to the
surface and are contained in the flow-back water stream from the
hydraulic fracturing of gas and oil formations.
[0028] As a result of the rapid increase in the extent and amount
of hydraulic fracturing of oil shale deposits being developed in a
number of different areas in the United States, there has arisen a
number of ecological and environmental concerns that must be
addressed if the industry is to grow successfully. For instance
toxic chemicals (such as glutaraldehyde) are used as a biocide to
kill, control, or eliminate, the water borne micro-organisms that
are present in the water used in the hydraulic fracturing process.
There is great concern such toxic chemical-bearing fracturing water
could migrate into a potable water aquifer. Also of concern is the
possibility of friction-reducing chemicals (e.g., polyacrylamide)
or scale inhibitors (e.g., phosphonate) finding their way into and
contaminating an aquifer. Detergent soap mixtures as well as
chemicals such as potassium chloride are commonly used as
surface-tension-reducing surfactants and could create public health
issues. The current practice of injecting brine-contaminated
flow-back water into disposal wells is another of concern to the
public.
[0029] In some examples of traditional fracturing jobs, after
explosively perforating a horizontal well casing, a water mixture
is injected at high pressure into a multitude of individually
sequenced fracturing zones, each being sealed off at both ends by
packer sleeves. This allows the water mixture to remain in the
shale formation under pressure for several days, creating channels,
fractures, or fissures which, when the hydraulic pressure is
released by a coiled drilling operation, allow hydrocarbon gas and
liquid elements to have passageways that allow flow to the surface.
For each individual fracturing zone, the pressure in the water
mixture is reduced in sequence so that the depressurized water
flows back horizontally into the well bore and then proceeds upward
in the vertical cemented well section to the ground surface
elevation. Much of the proppant remains behind in these channels;
however, a significant amount comes out in the back-flow water.
[0030] The flow-back water volume accounts for less than fifty
percent of the amount of injected water used for the fracturing
operation. The flow-back water stream also contains materials that
are leached out of the shale formation such as bicarbonates, (e.g.,
nahcolities). The flow-back water mixture also carries with it many
volatile organic compounds as well as the micro-organism debris,
any dissolved salts or brines, and a significant amount of the
initially-injected proppant and their produced fines. Treatment
and/or disposal of this flow-back are significant issues for the
industry. For example, see Smyth, Julie Carr. (2012). Ohio quakes
put pressure on use of fracturing. Associated Press. pp. D1, D6.
Lowry, Jeff, et al. (2011 December). Haynesville trial well applies
environmentally focused shale technologies. World Oil. pp. 39-40,
42. Beckwith, Robin. (2010 December). Hydraulic Fracturing The
Fuss, The Facts, The Future. JPT. pp. 34-35, 38-41. Ditoro, Lori K.
(2011). The Haynesville Shale. Upstream Pumping Solutions. pp.
31-33. Walser, Doug. (2011). Hydraulic Fracturing in the
Haynesville Shale: What's Different? Upstream Pumping Solutions.
pp. 34-36. Bybee, Karen. (2011 March). In-Line-Water-Separation
Prototype Development and Testing. JPT. pp. 84-85. Bybee, Karen.
(2011 March). Produced-Water-Volume Estimates and Management
Practices. JPT. pp. 77-79. Katz, Jonathan. (2012 May). Report:
Fracking to Grow U.S. Water-Treatment Market Nine-Fold by 2020.
Industry Week. U.S. App. Pub. No. 2012/0012307A1; U.S. App. Pub.
No. 2012/0024525A1; U.S. App. Pub. No. 2012/0070339A1; U.S. App.
Pub. No. 2012/0085236A1; U.S. App. Pub. No. 2012/0097614A1. Each of
the above references are incorporated herein by reference for all
purposes.
[0031] Currently, it is common practice to kill micro-organisms
that are in the water mixture, either initially or insitu, by
chemical or other types of biocides, so that the gaseous and liquid
hydrocarbons that are trapped in the oil shale's matrix formation
can flow freely into the channels and fissures vacated by the
flow-back water mixture. Also, the channels created by the
fracturing process must be kept open by the proppants that are
initially carried into the fissures in the fracture zones by the
injected water mixture. If the micro-organisms are not killed they
will multiply, rapidly; and, if they remain in the fissures, they
will grow and reduce or entirely block the flow hydrocarbons from
these fissures. Another significant micro-organism type problem is
the possible presence of a strain of microbes that have an affinity
for seeking out and digesting any free sulfur or sulfur bearing
compounds and producing hydrogen sulfides that must be removed from
any product gas stream because it is a highly dangerous and
carcinogenic material. All these types of micro-organisms must be
destroyed if this type of problem is to be avoided.
[0032] In addition to the possibility of micro-organisms
multiplying and blocking the flow of hydrocarbon product, the
presence of dissolved solids in the water solution can also be a
problem in the injected water mixture. They can deposit themselves
as scale or encrustations in the same flow channels and fissures.
These encrustations, if allowed to be deposited in these channels,
will also reduce or block the flow of hydrocarbons to the surface.
In order to avoid this condition, attempts are made in current
industry practice to have the dissolved solids coalesce and attach
themselves to the suspended or other colloidal particles present in
the water mixture to be removed before injection in the well;
however, those efforts are only partly effective. See, e.g. Denny,
Dennis. (2012 March). Fracturing-Fluid Effects on Shale and
Proppant Embedment. JPT. pp. 59-61. Kealser, Vic. (2012 April).
Real-Time Field Monitoring to Optimize Microbe Control. JPT. pp.
30, 32-33. Lowry, Jeff, et al. (2011 December). Haynesville trial
well applies environmentally focused shale technologies. World Oil.
pp. 39-40, 42. Rassenfoss, Stephen. (2012 April). Companies Strive
to Better Understand Shale Wells. JPT. pp. 44-48. Ditoro, Lori K.
(2011). The Haynesville Shale. Upstream Pumping Solutions. pp.
31-33. Walser, Doug. (2011). Hydraulic Fracturing in the
Haynesville Shale: What's Different? Upstream Pumping Solutions.
pp. 34-36. Denney, Dennis. (2012 March). Stimulation Influence on
Production in the Haynesville Shale: A Playwide Examination. JPT.
pp. 62-66. Denney, Dennis. (2011 January). Technology Applications.
JPT. pp. 20, 22, 26. All of the above are incorporated herein by
reference for all purposes.
[0033] In recent years, the oil industry has tried to develop a
number of ways to address these concerns. The use of ultra violet
light in conjunction with reduced amounts of chemical biocide has
proven to be only partially effective in killing water borne
micro-organisms. This is also true when also trying to use
ultra-high frequency sound waves to kill micro-organisms. Both
these systems, however, lack the intensity and strength to
effectively kill all of the water-borne micro-organisms with only
one weak short time residence exposure and with virtually no
residual effectiveness. Both systems need some chemical biocides to
effectively kill all the water borne micro-organisms that are in
water. Also, some companies use low-frequency or low-strength
electro-magnetic wave generators as biocide/coalescers; however,
these too have proven to be only marginally effective.
[0034] Therefore, an object of further examples is to economically
address and satisfactorily resolve some of the major environmental
concerns that are of industry-wide importance. Objects of still
further examples are to eliminate the need for brine disposal
wells, eliminate the use of toxic chemicals as biocides for
micro-organism destruction, or for scale prevention, and the
recovery of all flow-back or produced water for reuse in subsequent
hydraulic fracturing operations. Examples of the invention provide
technically sound and economically viable solutions to many of the
public safety issues that have concerned the industry in hydraulic
fracturing.
SUMMARY OF EXAMPLES OF THE INVENTION
[0035] Advantages of various examples of the present invention
include the need for less (or no) disposal of brine water, since
substantially all dissolved salts are coalesced and converted into
suspended particles that are separated and incorporated with
recovered proppant and fines for inclusion in a feed material for
fusion by pyrolysis in a rotary kiln. Similarly, examples of the
invention eliminate the need for chemical biocides since the high
intensity, variable, ultra-high frequency electromagnetic wave
generator kills the micro-organisms that are present in water
before water is injected into the formation. The electromagnetic
wave also prevents the formation of scale encrustations; therefore,
there is no need to add scale inhibitors to the fracturing water
mixture. As a result, substantially all the flow-back water from a
fracturing operation is reused with all the remaining solid
materials being recycled and reconstituted into
appropriately-constituted and properly sized proppants for
subsequent use in fracturing operations. In addition, since
volatile organic compounds are burned and vaporized, there is no
need for any sludge or other types of solid waste disposal
facilities.
[0036] According to one aspect of the invention, a system for use
in well fracturing operations is provided, comprising: a first
separator including a slurry intake and a slurry output with a
first water content; a second separator having a slurry input,
positioned to receive slurry from the slurry output of the first
separator, and a slurry output with a second, lower water content;
a kiln positioned to receive the slurry output of the second
separator and having an output; a quench positioned to receive slag
from the output of the kiln; a crusher positioned to receive
quenched slag from the quench; a mill positioned to receive crushed
material from the crusher; a first screen positioned to receive
milled material from the mill, the size of the screen wherein the
size of the first screen determines the upper boundary of the
proppant size; and a second screen positioned to receive material
passed by the first screen, wherein the size of the second screen
determines the lower boundary of the proppant size. In at least one
example, the system further comprises a proppant storage silo
positioned to receive proppant from between the first and the
second screens. In a further example, the system also includes a
blender positioned to receive proppant from the silo. In a more
specific example, the first separator includes a water output and
the system further includes: a water storage tank positioned to
receive water from the first separator, a biocide coalescer
positioned to receive water from the water storage tank, the
coalescer having an output feeding the blender, and at least one
fracture pump receiving at least proppant and water from the
blender, wherein the fracturing pump produces flow in water for
well fracturing operations.
[0037] According to a further example of the invention, a method is
provided for creating a proppant of a specific size from a slurry
extracted from a fractured hydrocarbon well, the method comprising:
separating water from the slurry, resulting in a slurry stream and
a liquid stream; mixing the slurry stream with particulate,
resulting in a feed material; fusing proppant material in the feed
material; quenching the fused proppant material; breaking the fused
proppant material; sizing the broken material for the specific
size; and mixing broken material that is not of the specific size
with the feed material. In some examples of the invention, the
method further comprises extracting the slurry from the flow of
produced fluid from a hydrocarbon well, wherein the produced fluid
includes water and a slurry, wherein the separating of the slurry
results in at least two streams, wherein one of the at least two
streams comprises a substantially liquid stream of water and
another of the at least two streams comprises the slurry. Examples
of acceptable means for separating the slurry from a flow of
produced fluid from a hydrocarbon well include a conventional
three-phase separator.
[0038] In at least one example, the mixing comprises: injecting the
solid stream into a kiln; and injecting particulate into the kiln,
wherein the injection of the particulate changes the viscosity of a
slagging material wherein the slagging material comprises the solid
stream and the injected particulate. In a further example, the
injecting particulate into the kiln is dependent upon the viscosity
of the slagging material in the kiln wherein the injecting of the
particulate is increased when the slagging material is too viscous
for even flow in the kiln. In some examples, the injecting of the
particulate is decreased when the slagging material viscosity is so
low that the flow rate through the kiln is too fast for fusing of
proppant material.
[0039] In a further example, the quenching comprises spraying the
fused proppant material with the liquid stream and the breaking
comprises: crushing the quenched proppant material and grinding the
crushed proppant material.
[0040] In still another example the sizing comprises screening
and/or weight-separating. In some examples, the fusing comprises
heating the slagging material wherein volatile components in the
slagging material are released in a gas phase and proppant material
in the slagging material is fused. In some such examples, the rate
of flow of the fused material outputting a kiln is measured, and
the heating in the kiln is adjusted, based on the measuring.
[0041] In yet another example, the method further includes
separating the slurry from a flow of produced fluid from a
hydrocarbon well, wherein the produced fluid includes water and
solids, wherein said separating the slurry results in at least two
streams, and wherein one of the at least two streams comprises a
substantially liquid stream of water and another of the at least
two streams comprises the slurry. In at least one such example, the
method also includes imparting an electromagnetic pulse to the
substantially liquid stream of water, wherein proppant is mixed
with the substantially liquid stream of water before or after the
imparting.
[0042] According to a further aspect of the of the invention, a
system is provided for creating a range of proppant of specific
sizes from a slurry extracted from a fractured hydrocarbon well,
the system comprising: means for separating water from the slurry,
resulting in a slurry stream and a liquid stream; means for mixing
the slurry stream with particulate, resulting in a feed material;
means for fusing proppant material in the feed material; means for
quenching the fused proppant material; means for breaking the fused
proppant material; means for sizing the broken material for the
specific size; and means for mixing broken material that is not of
the specific size with the feed material. In at least one example,
the means for mixing broken material that is not of the specific
size comprises the means for fusing.
[0043] An example of the means for separating includes at two-phase
separation tank with a funnel at a lower end with a conduit leading
to the input to an auger. A two-phase separation tank uses the
principle of gravity-precipitating unit (with or without baffles).
An alternative to a gravity-precipitation unit is a pressurized
tank from a hydrocone system forcing slurry to a feed-hopper with
an auger.
[0044] In a further example, the means for mixing the slurry stream
with particulate comprises: means for injecting the slurry stream
into a kiln; and means for injecting particulate into the kiln,
wherein the injection of the particulate changes the viscosity of a
slagging material and wherein the slagging material comprises the
slurry stream and the injected particulate. One example of useful a
means for injecting the slurry stream into the kiln include: an
auger from the means for separating to a kiln feed-hopper. As the
auger advances the slurry stream toward the hopper more water comes
off. Alternatives include a flight conveyor belt, a bucket
conveying system, and others that will occur to those of skill in
the art. Specific examples of useful means for injecting sand into
the kiln include: a bucket-elevator conveyor with a variable drive
bringing particulate (e.g. sand) from a silo where the specified
sand resides. The variable drive allows changing of the amount of
sand depending on the temperature measured at the exit of the kiln.
The temperature is related to viscosity. For example, as
temperature varies around some set point of about 2200 F, feed of
sand will be increased as temperature drops. It will be decreased
as temperature rises. In a more specific example, no change will be
made for a variation of about 5%, while, over 5%, the amount of
variation will cause increase or decrease in an amount that is
dependent on the particular kiln, proppant solid feed, and other
conditions that will occur to those of skill in the art. Other
examples of means for injecting include a belt conveyor or flight
conveyor and other equivalents that will occur to those of skill in
the art.
[0045] In a further example, the means for quenching comprises
means for spraying the fused proppant material with the liquid
stream that was separated from the slurry (e.g., with nozzles
and/or a water wall). A further alternative for cooling the
material would be air quenching. In at least one example, the hot
solids mixture from a kiln is deposited onto a moving, perforated
steel conveyor belt, which is placed over a water collection pan.
Water is applied to the mixture while on the belt.
[0046] In still a further example, the means for breaking
comprises: means for crushing the quenched proppant material; and
means for grinding the crushed proppant material. In one such
example, the means for crushing comprises a crusher having the
following specifications: an eccentric gyratory crusher (conical)
so that the crushing space can be varied to obtain various sizes.
Alternative crushers include: jaw crushers, roller crushers, ball
crushers, and other equivalents that will occur to those of skill
in the art. In some examples, the crusher reduces a solidified,
agglomerated mixture into pieces having a size range of about 1/4
inch to about 1/2 inch.
[0047] In some examples, the means for grinding comprises a grinder
of the following type: a rod mill, a ball mill, an autogenous mill,
bowl mill, and other equivalents that will occur to those of skill
in the art. In at least some such examples, crushed material is
moved by conveyor and discharged into a mixing/grinding unit where
the materials are reduced in size; in at least one example, 98-99%
of the material passes through a #30 sleeve opening of about 590
microns, and the passes material is similar in size and strength to
sharp, fine sand.
[0048] In some examples, the means for sizing comprises a screener
having at least one screen. An example of a screener that is
acceptable is a vibrating screen. If the material passes the
screen, it is classified as "specification size." If it is too
small, it drops out to an undersized feed that is fed back to the
input of the hopper of the kiln. If it is too large, it is
separated into an oversized feed that is provided to the hopper at
the input of the kiln. In at least one example, the over and
undersized streams are combined before they are injected into the
kiln. Other acceptable means for sizing includes fixed screens,
rotating screens, and means for weight-separating (e.g., a cyclone
through which broken material passes and/or specific gravity
separation in liquid solution). Examples of acceptable cyclones
will occur to those of skill in the art. Another acceptable means
for separating includes specific gravity separation in liquid
solution. Acceptable separation systems of that type will occur to
those of skill in the art.
[0049] According to a further example, the means for fusing
comprises means for heating the slagging material wherein volatile
components in the slagging material are released in a gas phase and
proppant material in the slagging material is fused. One example of
such a means for heating the slagging material includes a slagging
rotary kiln, an inclined rotary kiln, and a horizontal kiln with
both direct and indirect firing capabilities. Alternative means for
fusing proppant material in the feed material include: a
non-slagging kiln, a vertical furnace (e.g. a Hershoff furnace, a
Pacific, multi-hearth, vertical furnace), a horizontal traveling
grate sintering furnace, and other equivalents that will occur to
those of skill in the art. In some examples, the kiln operation
involves feeding the slurry materials into the kiln and adding
proppant to start the process of fusing the slurry material and
proppant together into a flowing agglomerate material mass. As the
mixture moves down to the kiln discharge port, the temperature of
the mixture increases due to the heat being generated by the kiln's
burner. At the same time, the viscosity of the mixture decreases as
the temperature increases. During this same period of time, the
organic materials which are carried in the mixture are burned,
vaporized, and discharged into a vent stack, leaving a flowing
solids material mixture. The viscosity of this flowing mixture is
adjusted by either increasing or decreasing the heat released by
the kiln's burner, or by adding more or less proppant to the
mixture, or both.
[0050] Some examples of the invention also include means for
measuring the rate of flow of the fused material outputting the
kiln. Examples of means for measuring the flow of the fused
material outputting the kiln includes a temperature sensor
providing a signal. Other equivalent means will occur to those of
skill in the art. A means for adjusting the heating in the kiln
based on the measuring is provided in still other embodiments.
Examples of means for adjusting the heating in the kiln based on
the measuring include: changing the flow of proppant input into the
kiln, based on the temperature measurement, and changing the rate
of fuel flow to the kiln burner to increase or decrease the amount
of heat being released in the kiln.
[0051] As mentioned above, the separating of the slurry from the
flow from a well results in at least two streams, wherein one of
the at least two streams comprises a substantially liquid stream of
water. And, in a still more detailed example, a means for imparting
an electromagnetic pulse to the substantially liquid stream of
water is provided. At least one example of a means for imparting an
electromagnetic pulse to the substantially liquid stream of water
is disclosed in U.S. Pat. No. 6,063,267, incorporated herein by
reference for all purposes. Alternatives to the device described in
that patent for use in various examples of the present invention
include: traditional biocide/coalescers (chemical, electrical, and
mechanical) as will occur to those of skill in the art.
[0052] In at least one example, the specific pulse imparted has the
following characteristics: variable, ultra-high frequencies in the
range of between about 10 and 80 kHz. Other pulses having
sufficient frequency to kill the micro-organisms present in water
and to cause dissolved solids to coalesce will occur to those of
skill in the art and may depend on the specific properties of the
water at a particular well. The pulse will generally rupture the
cells of the micro-organisms.
[0053] In still a further example of the invention, a means for
mixing proppant with the substantially liquid stream of water is
provided (for mixing either before or after the imparting).
Examples of means for mixing proppant with water included a blender
as will occur to those of skill in the art (for example, a screen
or open, grated tank). In some examples, surface tension reducing
agents are also added in the blender, as are other components that
will occur to those of skill in the art. The mixture is then
provided to a means of increasing the pressure of the mixture
(e.g., a fracturing pump--aka "intensifier unit"--as will occur to
those of skill in the art) and the pressurized mixture is injected
into a well.
[0054] In still further examples, proppant is made to specific
sizes from produced and/or flow-back water, as well as other
sources, using a combination of a kiln, crusher, mill, and screens,
to produce proppant of various sizes that those of skill in the art
will recognize as being desirable in fracturing operations. See,
e.g., Mining Engineering, "Industrial Materials", pp. 59-61, June
2012 (www.miningengineeringmagazine.com), incorporated herein by
reference. The various sizes are made by adjusting the mill and
screens used.
[0055] In still another example, a method is provided for treating
hydrocarbon well fracture water (which includes both "flow back"
and "produced" water) from a hydrocarbon well, wherein the method
comprises: separating solids from fracture water, wherein a flow of
water with suspended solids results; separating the flow of water
into a plurality of flows of water; generating positive charge in
the plurality of flows of water, wherein a plurality of flows of
positively-charged water results; comingling the plurality of flows
of positively-charged water after said generating. In a further
example, the method also comprises: monitoring an oil/water
interface level and controlling the oil/water interface level in
the separator.
[0056] In a more specific example, method further comprises slowing
the flow rate in the plurality of flows of water to be less than
the flow rate of the flow of water with suspended solids. Slowing
the flow rate allows for greater residence time during the step of
generating positive charge. That increases the amount of positive
charge in the water which is considered to be beneficial for
killing microbes in the water and for providing residual positive
charge for a period of time when the water has been injected into a
geologic formation from which hydrocarbons are to be produced. The
presence of positive charge in the water geologic formation is
believed to have benefits in reducing the presence of various
flow-reducing structures in the formation.
[0057] In a further specific example the method generating positive
charge in the flows of water comprises treating each of the
plurality of flows of water with electromagnetic flux.
[0058] In still a further example, the majority of the suspended
solids are less than about 100 microns. In some such examples,
substantially all the suspended solids are less than about 100
microns. In a more limited set of examples, the majority of the
suspended solids are less than about 10 microns. And in still a
more limited set of examples, substantially all the suspended
solids are less than about 10 microns. By reducing the size of the
suspended solids, it becomes possible to pass the water through
devices that are practical for generating positive charge in the
water at a reasonable cost by using, for example, stainless steel
conduits when the suspended solids approach 100 microns and softer
materials (for example, PVC) as the solids approach 10 microns and
smaller.
[0059] And some further examples, the separating comprises
two-stage separating. In at least one such example, two-stage
separating comprises: passing the fracture water through a
three-phase separator, wherein a water output from the three-phase
separator results, and passing the water output from the
three-phase separator through a two-phase separator. In at least
one such method, the three-phase separator comprises a
four-material separator having at least four outputs including: a
slurry, water having suspended solids therein, hydrocarbon liquid,
and hydrocarbon gas.
[0060] According to another example of the invention, a system is
provided for treating hydrocarbon well fracture water from a
hydrocarbon well, system comprising: means for separating solids
from fracture water, wherein a flow of water with suspended solids
results; means for separating the flow of water into a plurality of
flows of water; means for generating positive charge in the
plurality of flows of water, wherein a plurality of flows of
positively-charged water results; and means for comingling
plurality of flows of positively-charged water.
[0061] In at least one such system, the means for separating
comprises a three-phase, four material separator. For example, and
a more specific example, the means for separating further comprises
a second two phase separator, the two-phase separator comprising an
input for receiving water flow from the three-phase gas oil
separator, and an output for the flow of water with suspended
solids. In a further example, there is also provided: means for
monitoring an oil/water interface level; and means for controlling
the oil/water interface level in the first and second separator. In
one such example, the means for monitoring comprises an oil/water
interface level indicator and control valve sensor (for example, a
cascade control system).
[0062] In some examples, the means for separating the flow of water
into a plurality of flows of water comprises a manifold having an
input port to receive the flow of water with suspended solids and a
plurality of output ports, each of which has a cross-sectional area
that is smaller than the cross-sectional area of the input of the
manifold; and wherein the sum of the cross-sectional areas of the
output ports is greater than the cross-sectional area of the input
ports, whereby the flow rate exiting the manifold is less than the
flow rate entering the manifold. In at least one example, the
manifold comprises a 1:12 manifold (for example, having
cross-sectional diameters of 4 inches in the output ports and a
larger cross sectional diameter in the input ports). In an
alternative example, the means for separating the flow of water
into a plurality of flows of water comprises a water truck having a
plurality of compartments, each compartment being positioned to
receive a portion of the flow of water.
[0063] In a further example, the means for generating positive
charge comprises means for treating each of the plurality of flows
of water with electromagnetic flux. At least one such example, the
means for treating each of the plurality of flows of water with
electromagnetic flux comprises: a pipe; and at least one electrical
coil having an axis substantially coaxial with the pipe. In some
such examples, the pipe consists essentially of non-conducting
material. In some such examples, the pipe consists essentially of
stainless steel. In a variety of examples, there is also provided a
ringing current switching circuit connected to the coil. In some
such examples, the ringing current switching circuit operates in a
full-wave mode at a frequency between about 10 kHz to about 80
kHz.
[0064] In still a further example, the means for co-mingling
comprises a manifold having input ports for a plurality of flows of
positively-charged water and an output port. In one such example,
the means for co-mingling further comprises a well fracturing water
and proppant blender. In a variety of examples, the majority of the
suspended solids are less than about 100 microns. In some such
examples substantially all the suspended solids are less than about
100 microns. In a more limited set of examples, the majority of the
suspended solids are less than about 10 microns. In an even more
limited set of examples, substantially all the suspended solids are
less than about 10 microns.
[0065] In a more specific example, the means for separating
comprises a two-stage separator. In one such example, the two-stage
separator comprises: a three-phase separator having a water output
coupled to an input of a two-phase separator. In a further example,
three-phase separator comprises a four-material separator having at
least four outputs including: a slurry, water having suspended
solids therein, hydrocarbon liquid, and hydrocarbon gas.
[0066] In another example of the invention, a system is provided
for treatment of hydrocarbon well fracture water, the system
comprising: a multi-phase separator; a manifold having an input
port connected to an output of the multiphase separator and having
multiple output ports; a plurality of pipes, each having coils
wound on the pipe, wherein each pipe has an input end connected to
an output port of the manifold and each pipe has an output end; a
co-mingling manifold having input ports connected to the output
ends of the plurality of pipes.
[0067] In at least one such system, a proppant-water blender is
also provided that is connected to an output of the co-mingling
manifold.
[0068] In at least one such system, the multi-phase separator
comprises a multi-stage separator. In a more specific example, the
multi-stage separator comprises a two-stage separator, wherein: a
first stage of the two-stage separator comprises a three-phase
separator and a second stage of the two-stage separator comprises a
two-phase separator. In an even more specific example, the
three-phase separator comprises a four-material separator including
an oil-water interface control system.
[0069] In still another example of the invention, a method is
provided for controlling of water/liquid hydrocarbon interface in a
three-phase separator, the method comprising: establishing a
water/liquid hydrocarbon interface in a three-phase separator;
measuring the water/liquid hydrocarbon interface in the three-phase
separator, wherein a water/liquid hydrocarbon interface measurement
signal results; comparing the water/liquid hydrocarbon interface
measurement signal to a set point, wherein a comparison signal
results; reducing the flow-back or produced water into the
three-phase separator of hydrocarbon well fracture water when the
comparison signal indicates the water/liquid hydrocarbon interface
is above the set point; and increasing flow into the three-phase
separator when the comparison signal indicates the water/liquid
hydrocarbon interface is below the set point, wherein the
increasing flow comprises hydrocarbon well fracture water from a
well and make-up water from a storage tank or a lagoon.
[0070] In a further example, the method also comprises: decreasing
the flow exiting the three-phase separator at the same rate in
balance with the flow as it decreases into the three-phase
separator, and increasing the flow exiting the three-phase
separator at the same balanced rate as the flow increases into the
three-phase separator.
[0071] In another example, a system is provided for controlling of
water/liquid hydrocarbon interface in the three-phase separator,
where in the system comprises: means for establishing a
water/liquid hydrocarbon interface in a three-phase separator;
means for measuring the water/liquid hydrocarbon interface in the
three-phase separator, wherein a water/liquid hydrocarbon interface
measurement signal results; means for comparing the water/liquid
hydrocarbon interface measurement signal to a set point, wherein a
comparison signal results; means for reducing the flow into the
three-phase separator of hydrocarbon well fracture water when the
comparison signal indicates the water/liquid hydrocarbon interface
is above the set point and for increasing flow into the three-phase
separator when the comparison signal indicates the water/liquid
hydrocarbon interface is below the set point, wherein the
increasing flow comprises hydrocarbon well fracture water and
make-up water.
[0072] In at least one example, the means for establishing a
water/liquid hydrocarbon interface comprises a diaphragm wier. In a
further example, the means for measuring the water/liquid
hydrocarbon interface comprises a liquid level indicator
controller-type sensor. In still a further example, comparing the
water/liquid hydrocarbon interface measurement signal to a set
point comprises a continuous capacitance level transmitter.
[0073] In some examples, the means for reducing and for increasing
the flow into the three-phase separator comprises a turbine type
flow meter and an inlet type control valve in-line with the input
of the three-phase separator.
[0074] In further examples, also provided are: means for decreasing
and balancing the flow exiting the three-phase separator at the
same rate as the flow decreases into the three-phase separator and
for increasing the flow exiting the three-phase separator at the
same balanced rate as the flow increases into the three-phase
separator.
[0075] In at least one such example the means for decreasing and
increasing the flow exiting the three-phase separator comprises a
flow-type meter connected in-line with the water output of the
three-phase separator. In another example, the means for decreasing
and increasing the flow exiting the three-phase separator comprises
an orifice-type flow controller controlling the water output of the
three-phase separator.
[0076] Examples of the inventions are further illustrated in the
attached drawings, which are illustrations and not intended as
engineering or assembly drawings and are not to scale. Various
components are represented symbolically; also, in various places,
"windows" into components illustrate the flow of material from one
location to another. However, those of skill in the art will
understand which components are normally closed. Nothing in the
drawings or detailed description should be interpreted as a
limitation of any claim term to mean something other than its
ordinary meaning to a person of skill in the various technologies
brought together in this description.
DESCRIPTION OF THE DRAWINGS
[0077] FIG. 1 is a diagram of a well site showing the flow of
various materials used in various examples of the invention.
[0078] FIGS. 2A and 2B, when connected along their respective
dotted lines, are a side view of an example of the invention.
[0079] FIG. 2A1 is an alternative to the embodiment of FIG. 2A.
[0080] FIG. 2C is a schematic of a control system used in at least
one example of the invention.
[0081] FIGS. 3A and 3B, when connected by the overlapping
components next to their dotted lines, are a plan view of the
example of FIGS. 2A and 2B.
[0082] FIGS. 3C and 3D are an isometric and side view,
respectively, of an aspect of the examples of FIGS. 2A-2B and FIGS.
3A-3B.
[0083] FIG. 4 is a side view of a further example of the
invention.
[0084] FIG. 5 is a plan view of the example of FIG. 4.
[0085] FIG. 6 is a diagram of a well site showing the flow of
various materials used in various examples of the invention.
[0086] FIG. 7 is a diagram of a well site showing the flow of
various materials used in various examples of the invention.
[0087] FIG. 8 is a top view of an example of the invention.
[0088] FIG. 9 is a side view of an example of the invention.
[0089] FIG. 10A is a side view of support leg 100 of FIG. 8.
[0090] FIG. 10B depicts a top view of foot 101 of FIG. 10A.
[0091] FIG. 11 is a cross section view taken through line A of FIG.
9.
[0092] FIG. 12 is a cross section view taken along line C of FIG.
8.
[0093] FIG. 13 is a cross section view taken along line B of FIG.
8.
[0094] FIG. 14A is a top view of a component of an example of the
invention.
[0095] FIG. 14B is a section view of the component of FIG. 14A.
[0096] FIG. 15 is a schematic of a control system useful in
examples of the invention.
[0097] FIG. 16 is a representational view of a system useful in
examples of the invention.
[0098] FIG. 17 is a schematic of a control system useful according
to examples of the invention.
[0099] FIG. 18 is a perspective view of examples of the
invention.
[0100] FIG. 19 is a perspective view of an apparatus embodying the
invention.
[0101] FIG. 20 is an exploded view of the pipe unit of the
apparatus of FIG. 19.
[0102] FIG. 21 is a longitudinal cross sectional view taken through
the pipe unit of FIG. 19.
[0103] FIG. 22 is a simplified circuit diagram of the pipe unit of
FIG. 19.
[0104] FIG. 23 is a detailed schematic diagram of the electrical
circuit of the pipe unit of FIG. 19.
[0105] FIG. 24 is a diagram showing certain wave shapes produced by
the pipe unit of FIG. 19 during operation.
[0106] FIG. 25 is a circuit diagram similar to FIG. 4 but showing a
modified embodiment of the invention.
[0107] FIG. 26 is a view similar to FIG. 21 but showing a modified
embodiment of the invention in which the pipe unit has only one
coil surrounding the liquid flow pipe.
[0108] FIG. 27 is a detailed circuit diagram similar to FIG. 23 but
showing an electrical circuit for use with the pipe unit of FIG.
27.
[0109] FIG. 28 is a chart specifying presently preferred values of
certain parameters of the apparatus of FIGS. 19 to 24.
DETAILED DESCRIPTION OF EXAMPLES OF THE INVENTION
[0110] Referring now to FIG. 1, a flow diagram of the use of the
invention in a hydrocarbon well having a well bore 1 with cemented
casing 3 passing through fracture zones that are isolated by
packers. Coil tubing 9 is inserted by rig 11 for fracture
operations known to those of skill in the art.
[0111] Flow back (and/or produced) water is routed to three-phase
solids/liquids/gas/hydrocarbon/water separator 10, from which any
hydrocarbon liquids and gases are produced, and water from
separator 10 is routed to a fracturing-water storage tank 17 which
may also include water from another source (aka "make up" water).
Wet solids are passed from three-phase separator 10 to two-phase
separator 14, which produces water that is passed to a quench
system 32 and slurry that are passed to kiln 24. Slag is passed
from kiln 24 through quench system 32 to crusher 40 and then to
mill 46. Milled material is separated into a specified size at
screen 50 that is sent to a proppant storage silo 26, which may
also include proppant from another source (e.g., a supplier of
sand). Water is provided to biocide/coalescer unit 13. Proppant
provided to blender 15 from silo 26, water is supplied to blender
15 from biocide/coalescer unit 13; the blended water and proppant
are then provided to fracturing pumps 19, which pumps the blend
into the well where it fractures the oil shale layer 21. Other
additives may be provided to the blender 15, as desired. Also,
proppant may be added to the water before the biocide/coalescer
unit 13 in alternative examples.
[0112] Examples of the invention create a range of proppants of
specific sizes from a slurry extracted from a
hydraulically-fractured hydrocarbon well.
[0113] In FIGS. 2A and 2C and in FIGS. 3A-3D, a more specific
example is seen. In that example, a slurry is extracted from
gravity-precipitated slurry that accumulates at the bottom of a
conventional three-phase separation tank 10 (which is of a common
design known to those of skill in the art). In the specific example
of FIG. 2A, as will occur to those of skill in the art, a
water/liquid hydrocarbon interface level facilitates the separation
and recovery of any liquid hydrocarbon product from the flow back
or produced water stream (which is under pressure as it enters
separator 10) by means of an internally or externally mounted water
level indicator (not shown). That indicator sends a water level
measurement signal to a pre-programmed, low level/high level water
flow control data integrator (not shown). When the water level in
the separator 10 reaches the high level set point, the data
integrator actuates a control valve (not shown) that controls flow
through the water feed pipe 10a (labeled "Inlet Water") to reduce
the amount of water going into the three phase separator, and the
rate of flow continues to decrease until a point is reached where
the incoming amount of water equalizes and balances out the volume
of water being withdrawn from the three phase separator.
Conversely, if the water level in the three phase separator 10
falls below the low level set point, the data integrator actuates
and further opens up the control valve in inlet pipe 10a in order
to increase the amount or rate of water flow that is sufficient to
stabilize the interface level. If this additional amount of water
is not sufficient to stabilize the water level at the interface
level, the integrator actuates a pump (not shown) and opens up
another control valve (not shown) which is located in a discharge
pipe (not shown) in water storage tank 17 (FIG. 1). That discharge
pipe is connected to the inlet pipe 10a; thus water from fracturing
water storage tank 17 continues to flow into the three phase
separator together with the flow back or produced water until the
water level in the separator 10 reaches the proper interface level.
Then, the make-up water control valve closes and the make-up water
pump is shut off. This control sequence is necessary in order to
achieve steady state and continuous operational stability in the
separation and recovery of any liquid hydrocarbon product that is
carried into the three phase separator by the flow back or produced
water feed stream.
[0114] A weir and baffle configuration (commonly known in gas/oil
separation units) facilitates the separation and recovery of the
liquid hydrocarbon product, if any, by using the interface level as
the maximum height of the water in the separator and allowing the
lighter liquid hydrocarbons to float on top of the water layer and
then be withdrawn as liquid hydrocarbon product after it flows over
the liquid hydrocarbon product weir and is withdrawn at the
hydrocarbon liquid product outlet flange connection. A horizontal
baffle under the weir limits the amount of potential water carry
over that might be comingled with the liquid hydrocarbon product
stream. As the flow back or produced water stream enters the three
phase separator 10 the depressurization releases the lighter
hydrocarbon gases and their release assists in the flotation of the
liquid hydrocarbon products as well as the release of the gaseous
hydrocarbon products through outlet 10c. Water flows out of
separator 10 through pipe 10b to a surge tank (not shown) and is
then pumped back to water tank 17 (FIG. 1).
[0115] From separator 10, a motor-driven positive displacement
diaphragm-type sludge pump 12 moves the slurry upwards to the inlet
opening of a two-phase water/solids separation tank 14 resulting in
a solid stream 16 and a liquid stream 18 that is pumped by pump 19
to a quench (labeled "Q"). From the bottom of the two-phase
water/solids separation tank 14, a bucket-elevator conveyor 20
transports the precipitated slurry materials from the lower part of
the water/solids separation tank 14 upwards from the water level
and discharges them into the feed-hopper 22 (FIG. 2B). The
discharge is seen in FIG. 2A as going over a dashed line, which
connects with the dashed line to the left of FIG. 2B where slurry
is seen accumulating in feed-hopper 22 of a slagging, rotary-kiln
24, leaving the slurry water to remain in the water/solids
separation tank 14 and the elevator 20. As a result, all separation
is carried out at atmospheric pressure rather than in
pressurized-vessels (as is current practice).
[0116] In the feed-hopper 22, the slurry materials from the
water/slurry separation tank are mixed with specification proppant
from silo 26 (FIG. 1), as well as under-sized and over-sized solid
materials that come from a final screening unit 50 (described
below).
[0117] As the fusion process for the proppant material proceeds,
inorganic proppant materials are fused into a uniform mass and
volatile organic materials that may have been present in the feed
stream from the water/solids separation tank 14 are burned and
vaporized prior to the gases being eventually discharged into an
exhaust vent 30.
[0118] The proppant material exiting from the rotary kiln 24 is
quenched with a stream of water to reduce the temperature of the
material, as it emerges from the outlet of the kiln 24. In some
examples, discharged material flows onto a perforated, motor-driven
stainless-steel conveyor belt 35 and the water cascades, through
spray nozzles 34 on to the moving belt 35 thereby solidifying and
cooling the proppant material. The water used for quenching the
proppant material comes from the water/solids separation tank 14
(see FIG. 2A) using, e.g., a motor-driven centrifugal pump 19 to
push the water to the quench nozzles 34 of FIG. 3B. An excess water
collection pan 36 is positioned under the conveyor belt 35 to
collect and recover any excess quench water and convey it back to
the water/solids separation tank 14 by a motor-driven centrifugal
pump 21 and a pipeline shown flowing to return "R" of FIG. 2A.
[0119] Quenching the hot proppant material, as it is discharged
from the kiln 24, causes a multitude of random,
differential-temperature fractures or cracks due to the uneven
contraction of the proppant material and the high internal stresses
caused by rapid quenching. The different sized pieces of proppant
material are discharged directly into the material crusher 40.
[0120] Crushing or breaking up the large irregular pieces of
proppant material and reducing their size is accomplished, in some
examples, by a motor-driven, vertical-shaft, gyratory, eccentric
cone or jaw crusher, known to those of skill in the art. The degree
of the size reduction is adjusted by changing the spacing or
crusher gap, thus allowing a range of different material sizes to
be produced, as is known to those of skill in the art.
[0121] Sizing of the proppant material is accomplished by the
grinding or milling of the crushed proppant material after the
proppant material is discharged at the bottom of the crusher. In
the illustrated example, the material is conveyed upwards to ball
mill 46 by a bucket-elevator conveyor 44. In at least one
alternative example, a rod mill is used. The mill 46 is adjusted to
grind the proppant material to different specific size ranges by
changing rotation, the size and spacing of the rods or balls in the
mill 46 (or its rotation).
[0122] The milled proppant material flows by gravity down through
the grinding zone of the mill and is discharged onto vibrating
screen 50 where the mesh openings are selectively sized to a
specific sieve value. For example, for soft mineral shale the mesh
openings are in the 590 micron range or a #30 sieve. For hard
mineral shale (for example) the mesh openings would be in the 150
micron range or a #100 sieve. Proppant material of the proper size
flows downward by gravity through a selectively sized screen
exiting at "A." Proppant material that is too large to pass through
the slanted, vibrating screen 53 exits onto belt 51a (seen better
in FIG. 3B), and the rest drops to screen 55. Proppant material
between the sizes of screens 53 and 55 exit as correctly sized
proppant at "A" and is transported to silo 26 (FIG. 1). Under-sized
proppant drops onto belt 51a which conveys the under-sized and
over-sized proppant to belt 51b, which then carries the proppant
back to kiln 24, through elevator 25. FIGS. 3A and 3B illustrate a
top view of an example of the invention in which the components are
mounted on a trailer or skid mounted that are assembled at a well
site with biocide and other components (e.g., FIGS. 4 and 5). Such
trailers or skids are leveled in some examples by leveling jacks
81.
[0123] As seen in FIGS. 3C and 3D, elevator 25 deposits material
into the top of feed hopper 22 and elevator 23 deposits material
from the silo into feed hopper 22 from a lower level through an
opening in feed hopper 22.
[0124] The properly-sized proppant materials flow is fed, by
gravity, into a specification proppant container (not shown) for
transfer to the specification proppant storage silo 26 (FIG. 1)
which may also contain specification proppant from another
source.
[0125] Referring now to FIG. 2B, it is desirable to control the
viscosity of the proppant feed mixture, to attain stability of
sustaining an optimum fusion temperature (in some examples,
approximately 2200 degrees Fahrenheit). As the proppant feed
mixture temperature is rising, due to the heat in kiln 24, the
process of fusing the various inorganic materials into a uniformly
viscous mass is achieved when the temperature in the proppant
mixture reaches the fusion temperature of silicon dioxide or sand.
The viscosity of the proppant material is a function of the
temperature of the material itself. Such control is accomplished in
various ways.
[0126] In at least one example, the temperature of the fused
material is measured, by any means know to those of skill in the
art, for example, an optical pyrometric sensor in quench system 32,
as it exits from the kiln. If the temperature is above the fusion
point of the material, it will be too liquid, and the fuel to the
kiln is reduced. At the same time, more specification proppant may
be added to the feed hopper 22. This affects the temperature
because the material coming from the slurry is not uniform and is
not dry; adding proppant from the silo evens out the
variability.
[0127] Referring now to FIG. 2C, a schematic is seen in which
sensor 67 signals integrator 69 with the temperature of the output
of the kiln 24. Integrator 69 then controls variable-speed motor 90
(FIG. 3A) that operates elevator 23 (see also FIG. 3B) that carries
proppant from the bottom of proppant silo 26 and discharges it into
the slagging rotary kiln feed-hopper 22. The different material
streams are comingled in the feed-hopper 22 before they enter the
revolving drum of the kiln 24. The proportion or amount of
specification proppant that is needed to be added to the material
stream from the water/solids tank 14 is adjusted, depending upon
the changes in the composition of the materials coming from the
water/solids separation tank 14. This increases uniformity of the
proppant material feed mixture that kiln 24 uses in the fusion
process. In at least one example, if the temperature is too high,
the fuel to the burner is reduced; if that does not correct it, the
amount of proppant to the kiln will be increased. Likewise, if the
temperature is too low, the fuel is increased to the burner; and,
if that does not work, the amount of proppant is decreased.
Alternative arrangements will occur to those of skill in the
art.
[0128] Referring back to FIG. 2C, integrator 69 also controls valve
63 to increase or decrease the supply of fuel 61 for kiln burner
65.
[0129] Referring again to FIG. 1, one example of the invention is
seen in which separator 10 is seen feeding the slurry to separator
14, and water from separator 10 is the joined with new "make-up"
(in tank 17) water to be used in injection in a new fracturing job.
The combined flows are treated by an electromagnetic
biocide/coalescer 13 of the type described in U.S. Pat. No.
6,063,267, incorporated herein by reference for all purposes
(commercially available as a Dolphin model 2000), which is set, in
at least one example, to impart an electro-magnetic pulse having
the following characteristics: selectable, variable, and tuneable
frequencies in a range between about 10-80 KHz. Such a pulse is
sufficient to kill biological organisms and to cause a positive
charge to be applied to the water, making the dissolved solids
capable of being precipitated or coalesced in the well.
[0130] FIGS. 4 and 5 are side and top views, respectively, of an
example trailer-mounted or skid-mounted system that includes a set
of biocide/coalescers 70a-70l, organized to receive fracturing tank
water in the type of flow rate used in common shale-fracture
operations. Such units are run from an electrical control panel 72,
that is connected to an overhead power and control distribution
rack 73 that connects to overhead power feed components 71a-71l.
Power is supplied by an engine 75 that turns an electrical
generator 77 that is connected to power feed 79 for supplying power
in a manner known to those of skill in the art.
[0131] Referring now to FIG. 2A1, an alternative to the embodiment
of FIG. 2A as seen in which the water level of two-phase separator
14 is at the same as the level and three-phase separator 10. In
such an embodiment, there is fluid communication through a
diaphragm pump 12 and tanks are at atmospheric pressure such that
the liquid gas interface is at the same level.
[0132] Referring now to FIG. 6, according to another example of the
invention, a system is provided for treating hydrocarbon well
fracture water from a hydrocarbon well, system comprising a means
for separating solids from fracture water comprising a three-phase,
four material separator 10, wherein a flow of water with suspended
solids results that is passed to a fracturing water storage tank
17. From there so-called "make-up water" may be added to fracture
water storage tank 17 and the flow of water is passed through a
means for separating the flow of water into a plurality of flows of
water (described in more detail below); to a means for generating
positive charge in the plurality of flows of water (for example, a
set of biocide coalescers or units as described above), wherein a
plurality of flows of positively-charged water results. A means for
comingling plurality of flows of positively-charged water more
evenly distributes the positive charge in the water before it is
passed to blender 15 for use in subsequent well fracturing
operations.
[0133] FIG. 7 illustrates an example in which the means for
separating further comprises a second stage, two-phase separator
14, the two-phase separator comprising an input for receiving water
flow from the three-phase gas oil separator. The water flow from
the three-phase separator is taken from the midsection of the
separator, while most solids dropped out at the bottom, as
described above. However, the water from the three-phase separator
includes suspended solids that can damage a biocide coalesce or
unit. Accordingly, in one example embodiment, the water flow from
the three-phase separator 10 is passed to the input of a two-phase
separator 14, which also includes an output for the flow of water
with suspended smaller suspended solids. Two-phase separator 14
also drops solids out of its lower section in the form of a slurry.
The slurry from three-phase separator 10 and two-phase separator 14
are further processed (for example as described above) or disposed
of in some other manner.
[0134] Referring now to FIGS. 8 and 9, an example of a three-phase,
four-material separator 90, useful according to some embodiments of
the invention and place of three-phase separator 10, as seen.
Separator 90 and includes an input 92, a slurry output 94, a liquid
hydrocarbon output 98 and a gas output 80. As also seen in FIG.
10A, separator 90 is supported by legs 100 (which includes a foot
101, as seen in FIG. 10B) welded to the side of separator 90.
[0135] Referring again to FIG. 9, as well as FIG. 11 (which is a
cross section taken through line A of FIG. 9) and FIG. 13 (which is
a cross-sectional taken along line B of FIG. 8), a baffle 111
allows water having some suspended solids to exit separator 90
while larger solids exit as the slurry at the bottom exit 94. FIG.
12 illustrates a cross-section of input 92 (taken along line C of
FIG. 8) where input pipe 92 is supported by support 120 connected
to the bottom of separator 90 and holding input pipe 92 and a
saddle.
[0136] In a further example, there is also provided: means for
monitoring an oil/water interface level; and means for controlling
the oil/water interface level in the first and second separator. In
one such example, the means for monitoring comprises an oil/water
interface level indicator and control valve sensor (for example, a
cascade control system).
[0137] As illustrated in FIG. 18, in some examples, the means for
separating the flow of water into a plurality of flows of water
comprises a manifold 181 having an input port valve 183 to receive
the flow of water with suspended solids from a means for separating
and a plurality of output ports attached to biocide coalescer units
184, each output port having a cross-sectional area that is smaller
than the cross-sectional area of the input of the manifold. In some
examples, the sum of the cross-sectional areas of the output ports
is greater than the cross-sectional area of the input ports,
whereby the flow rate exiting the manifold is less than the flow
rate entering the manifold. In at least one example, the manifold
181 comprises a 1:12 manifold (for example, having cross-sectional
diameters of 4 inches in the output ports and a larger cross
sectional diameter in the input ports). In an alternative example,
the means for separating the flow of water into a plurality of
flows of water comprises a water truck as is known in the art (not
shown) having a plurality of compartments, each compartment being
positioned to receive a portion of the flow of water. In operation,
water passes through valve 183 into manifold 181 and the flow is
slowed as it is separated into parallel flows through the
parallel-connected biocide coalescer units 184 to increase
residence time for imparting electromagnetic flux in order to
maximize the positive charges the electromagnetic flux imparts to
the water. The output of the units 184 is comingled in manifold
186, who's output is controlled by valve 188. The entire assembly
of the manifolds and biocide coalescer units is, in some examples,
mounted on frame 184 which may be lifted by harness 186 onto a pad
at a well site or onto the bed of a truck for transportation.
[0138] In a further example, the means for generating positive
charge comprises means for treating each of the plurality of flows
of water with electromagnetic flux. At least one such example is
seen in FIGS. 19-28, where the means for treating each of the
plurality of flows of water with electromagnetic flux comprises: a
pipe and at least one electrical coil having an axis substantially
coaxial with the pipe. In some such examples, the pipe consists
essentially of non-conducting material. In some such examples, the
pipe consists essentially of stainless steel. In a variety of
examples, there is also provided a ringing current switching
circuit connected to the coil. In some such examples, the ringing
current switching circuit operates in a full-wave mode at a
frequency between about 10 kHz to about 80 kHz.
[0139] Specifically, still referring to FIGS. 19-28, turning first
to FIG. 19, an apparatus embodying the invention is indicated
generally at 910 and comprises basically a pipe unit 912 and an
alternating current electrical power supply 914. The pipe unit 912
includes a pipe 916 through which liquid to be treated passes with
the direction of flow of liquid being indicated by the arrows A.
The pipe 916 may be made of various materials, but as the treatment
of the liquid effected by the pipe unit 912 involves the passage of
electromagnetic flux through the walls of the pipe and into the
liquid passing through the pipe, the pipe is preferably made of a
non-electrical conducting material to avoid diminution of the
amount of flux reaching the liquid due to some of the flux being
consumed in setting up eddy currents in the pipe material. Other
parts of the pipe unit 912 are contained in or mounted on a
generally cylindrical housing 918 surrounding the pipe 916.
[0140] The pipe unit 912 is preferably, and as hereinafter
described, one designed for operation by a relatively low voltage
power source, for example, a power source having a voltage of 911
V(rms) to 37 V(rms) and a frequency of 60 Hz and, therefore, the
illustrated power supply 914 is a voltage step down transformer
having a primary side connected to an input cord 920 adapted by a
plug 922 for connection to a standard mains, such as one supplying
electric power at 120 V 60 Hz or 240 V 60 Hz, and having an output
cord 924 connected to the secondary side of the transformer and
supplying the lower voltage power to the pipe unit 912. The pipe
unit 912 may be designed for use with pipes 916 of different
diameter and the particular output voltage provided by the power
source 914 is one selected to best suit the diameter of the pipe
and the size and design of the related components of the pipe
unit.
[0141] The pipe unit 912, in addition to the housing 918 and pipe
916, consists essentially of an electrical coil means surrounding
the pipe and a switching circuit for controlling the flow of
current through the coil means in such a way as to produce
successive periods of ringing current through the coil means and
resultant successive ringing periods of electromagnetic flux
passing through the liquid in the pipe 916. The number, design and
arrangement of the coils making up the coil means may vary, and by
way of example in FIGS. 20 and 21 the coil means is shown to
consist of four coils, L.sub.1, L.sub.2-outer, L.sub.2-inner and
L.sub.3 arranged in a fashion similar to that of U.S. Pat. No.
5,702,600, incorporated herein by reference for all purposes. The
coils, as shown in FIGS. 20 and 21, are associated with three
different longitudinal sections 926, 928 and 930 of the pipe 916.
That is, the coil L.sub.1 is wound onto and along a bobbin 932 in
turn extending along the pipe section 926, the coil L.sub.3 is
wound on and along a bobbin 934 itself extending along the pipe
section 930, and the two coils L.sub.2-inner and L.sub.2-outer are
wound on a bobbin 936 itself extending along the pipe section 928,
with the coil L.sub.2-outer being wound on top of the coil
L.sub.2-inner. The winding of the two coils L.sub.2-inner and
L.sub.2-outer on top of one another, or otherwise in close
association with one another, produces a winding capacitance
between those two coils which forms all or part of the capacitance
of a series resonant circuit as hereinafter described.
[0142] Referring to FIG. 20, the housing 918 of the pipe unit 912
is made up of a cylindrical shell 938 and two annular end pieces
940 and 942. The components making up the switching circuit are
carried by the end piece 940 with at least some of them being
mounted on a heat sink 944 fastened to the end piece 940 by screws
946. In the assembly of the pipe unit 912, the end piece 940 is
first slid onto the pipe 916, from the right end of the pipe as
seen in FIG. 20, to a position spaced some distance from the right
end of the pipe, and is then fastened to the pipe by set screws
948. The three coil bobbins 932, 936 and 934, with their coils, are
then moved in succession onto the pipe 916 from the left end of the
pipe until they abut one another and the end piece 940, with
adhesive applied between the bobbins and the pipe to adhesively
bond the bobbins to the pipe. An annular collar 950 is then slid
onto the pipe from the left end of the pipe into abutting
relationship with the coil L.sub.3 and is fastened to the pipe by
set screws 960, 960. The shell 938 is then slid over the pipe and
fastened at its right end to the end piece 940 by screws 962, 962.
Finally, the end piece 942 is slid over the pipe 916, from the left
end of the pipe, and then fastened to the shell 938 by screws 964
and to the pipe by set screws 966.
[0143] The basic wiring diagram for the pipe unit 912 is shown in
FIG. 22. The input terminals connected to the power source 914 are
indicated at 968 and 970. A connecting means including the
illustrated conductors connects these input terminals 968 and 970
to the coils and to the switching circuit 972 in the manner shown
with the connecting means including a thermal overload switch 974.
The arrow B indicates the clockwise direction of coil winding, and
in keeping with this reference the coil L.sub.3 and the coil
L.sub.2-outer are wound around the pipe 916 in the clockwise
direction and the coils L.sub.1 and L.sub.2-inner are wound around
the pipe in the counterclockwise direction. Taking these winding
directions and the illustrated electrical connections into account,
it will be understood that when a current i.sub.c flows through the
coils in the direction indicated by the arrows C, the directions of
the magnetic fluxes passing through the centers of each of the
coils, and therefore through the liquid in the pipe, are as shown
by the arrows E, F, G and H in FIG. 22. That is, the fluxes passing
through the centers of the coils L.sub.1, L.sub.2-inner and L.sub.3
move in one direction longitudinally of the pipe and the flux
passing through the center of the coil L.sub.2-outer moves in the
opposite direction. Depending on the design of the switching
circuit 972, it may be necessary or desirable to provide a local
ground for the switch circuit 972 and when this is the case, the
switching circuit may be connected with the input terminals 968 and
970 through an isolation transformer 976, as shown in FIG. 22.
[0144] FIG. 23 is a wiring diagram showing in greater detail the
connecting means and switching circuit 972 of FIG. 22. Referring to
FIG. 23, the switching circuit 972 includes a 12 V power supply
subcircuit 976, a comparator subcircuit 978, a timer subcircuit
980, a switch 982 and an indicator subcircuit 984.
[0145] The components D2, R5, C5, R6 and Z1 comprise the 12 V DC
power supply subcircuit 976 which powers the other components of
the trigger circuit. Resistors R1 and R2 and the operational
amplifier U1 form the comparator subcircuit 978. The resistors R1
and R2 form a voltage divider that sends a signal proportional to
the applied AC voltage to the operational amplifier U1. The
capacitor C1 serves to filter out any "noise" voltage that might be
present in the AC input voltage to prevent the amplifier U1 from
dithering. The amplifier U1 is connected to produce a "low" (zero)
output voltage on the line 986 whenever the applied AC voltage is
positive and to produce a "high" (+12 V) output when the AC voltage
is negative.
[0146] When the AC supply voltage crosses zero and starts to become
positive, the amplifier U1 switches to a low output. This triggers
the 555 timer chip U2 to produce a high output on its pin 93. The
capacitor C2 and R3 act as a high-pass filter to make the trigger
pulse momentary rather than steady. The voltage at pin 92 of U2 is
held low for about one-half millisecond. This momentary low trigger
voltage causes U2 to hold a sustained high (+12 V) on pin 93.
[0147] The switch 982 may take various different forms and may be a
sub-circuit consisting of a number of individual components, and in
all events it is a three-terminal or triode switch having first,
second and third terminals 988, 990 and 992, respectively, with the
third terminal 992 being a gate terminal and with the switch being
such that by the application of electrical signals to the gate
terminal 992 the switch can be switched between an ON condition at
which the first and second terminals are closed relative to one
another and an OFF condition at which the first and second
terminals are open relative to one another. In the preferred and
illustrated case of FIG. 23, the switch 982 is a single MOSFET
(Q1). The MOSFET (Q1) conducts, that is sets the terminals 988 and
990 to a closed condition relative to one another, as soon as the
voltage applied to the gate terminal 992 becomes positive as a
result of the input AC voltage appearing across the input terminals
968 and 970 becoming positive. This in turn allows current to build
up in the coils L.sub.1, L.sub.2-inner, L.sub.2-outer, and L.sub.3.
When the time constant formed by the product of the resistor R4 and
the capacitor C3 has elapsed, the 555 chip U2 reverts to a low
output at pin 93 turning the MOSFET (Q1) to its OFF condition. When
this turning off of (Q1) occurs, any current still flowing in the
coils is diverted to the capacitance which appears across the
terminals 988 and 990 of (Q1). As shown in FIG. 23, this
capacitance is made up of the wiring capacitance C.sub.c arising
principally from the close association of the two coils
L.sub.2-inner and L.sub.2-outer. This winding capacitance may of
itself be sufficient for the purpose of creating a useful series
resonant circuit with the coils, but if additional capacitance is
needed, it can be supplied by a separate further tuning capacitor
(C.sub.t).
[0148] When the switch (Q1) turns to the OFF or open condition, any
current still flowing in the coils is diverted to the capacitance
(C.sub.c and/or C.sub.t) and this capacitance in conjunction with
the coils and with the power source form a series resonant circuit
causing the current through the coils to take on a ringing wave
form and to thereby produce a ringing electromagnetic flux through
the liquid in the pipe 916. By adjusting the variable resistor R4,
the timing of the opening of the switch (Q1) can be adjusted to
occur earlier or later in each operative half cycle of the AC input
voltage. Preferably, the circuit is adjusted by starting with R4 at
its maximum value of resistance and then slowly adjusting it toward
lower resistance until the LED indicator 994 of the indicator
subcircuit 984 illuminates. This occurs when the peak voltage
developed across the capacitance (C.sub.c and/or C.sub.t) exceeds
150 V at which voltage the two Zener diodes Z2 can conduct. The
Zener diodes charge capacitor 962 and the resulting voltage turns
on the LED 994. When this indicator LED lights, the adjustment of
the resistor R4 is then turned in the opposite direction until the
LED just extinguishes, and this accordingly sets the switch (Q1) to
generate a 150 V ringing signal.
[0149] FIG. 24 illustrates the function of the circuit of FIG. 23
by way of wave forms which occur during the operation of the
circuit. Referring to this Figure, the wave form 996 is that of the
AC supply voltage applied across the input terminals 968 and 970,
the voltage being an alternating one having a first set of half
cycles 998 of positive voltage alternating with a second set of
half cycles 900 of negative voltage. The circuit of FIG. 23 is one
which operates in a half wave mode with periods of ringing current
being produced in the coils of the pipe unit only in response to
each of the positive half cycles 998. The wave form 902 represents
the open and closed durations of the switch (Q1), and from this it
will be noted that during each positive half cycle 998 of the
supply voltage the switch (Q1) is closed during an initial portion
of the half cycle and is opened at a time well in advance of the
end of that half cycle (with the exact timing of this occurrence
being adjustable by the adjustable resistor R4).
[0150] The opening and closing of the switch (Q1) produces the
current wave form indicated at 904 in FIG. 24 which for each
positive half cycle of the supply voltage is such that the current
through the coils increases from zero during the initial portion of
the half cycle, during which the switch (Q1) is closed, and then
upon the opening of the switch (Q1) the current rings for a given
period of time. The voltage appearing across the coils of the pipe
unit is such as shown by the wave form 906 of FIG. 24, with the
voltage upon the opening of the switch (Q1) taking on a ringing
shape having a maximum voltage many times greater than the voltage
provided by the power supply 914.
[0151] The frequency of the ringing currents produced in the coils
and of the ringing voltages produced across the coils can be varied
by varying the capacitance (C.sub.c and/or C.sub.t) appearing
across the switch (Q1) and is preferably set to be a frequency
within the range of 10 kHz to 80 kHz.
[0152] Parameters of the apparatus of FIGS. 19-24, including
nominal pipe size, arrangement of coils in terms of number of
turns, gage and length, tuning capacitor capacitance and associated
nominal power supply voltage are given in the form of a chart in
FIG. 28.
[0153] As mentioned above, the switching circuit illustrated and
described in connection with FIGS. 22, 23 and 24 is one which is
operable to produce one period of ringing current and ringing
voltage for each alternate half cycle of the applied supply
voltage. However, if wanted, the switching circuit can also be
designed to operate in a full wave mode wherein a period of ringing
current and of ringing voltage is produced for each half cycle of
the supply voltage. As shown in FIG. 25, this can be accomplished
by modifying the circuit of FIG. 22 to add a second switching
circuit 908 which is identical to the first switching circuit 972
except for facing current wise and voltage wise in the opposite
direction to the first circuit 972. That is, in FIG. 25 the first
circuit 972 operates as described above during each positive half
cycle of the applied voltage and the second circuit 908 operates in
the same way during the negative half cycles of the applied
voltage, and as a result, the number of periods of current and
voltage ringing over a given period of time is doubled in
comparison to the number of periods produced in the same period of
time by the circuit of FIG. 22.
[0154] Also, as mentioned above, the number of coils used in the
pipe unit 912 may be varied and if wanted, the pipe unit 912 may be
made with only one coil without departing from the invention. FIGS.
26 and 27 relate to such a construction with FIG. 26 showing the
pipe unit to have a single coil 910 wound on a bobbin 912 and
surrounding the pipe 916. The switching circuit used with the
single coil pipe unit of FIG. 26 is illustrated in FIG. 27 and is
generally similar to that of FIG. 23 except, that because of the
single coil 910 producing no significant wiring capacitance, it is
necessary to provide the tuning capacitor (C.sub.t) across the
first and second terminals 988 and 990 of the switch (Q1). Further,
since the coil means is made up of the single coil 910 and located
entirely on one side of the switch (Q1), it is unnecessary to
provide the isolation transformer 976 of FIG. 23 to establish a
local ground for the components of the switching circuit.
[0155] In still a further example, seen in FIG. 18 means for
co-mingling comprises a manifold 186 having input ports for a
plurality of flows of positively-charged water from multiple means
for generating positive charge 184 and an output port connected to
valve 188 directing an output flow of water having positive charges
therein to a blender for use in well fracturing operations. In a
variety of examples, the majority of the suspended solids are less
than about 100 microns. In some such examples substantially all the
suspended solids are less than about 100 microns. In a more limited
set of examples, the majority of the suspended solids are less than
about 10 microns. In an even more limited set of examples,
substantially all the suspended solids are less than about 10
microns.
[0156] Referring now to FIGS. 16 and 17, a system is shown for
controlling of water/liquid hydrocarbon interface in the
three-phase separator, where in the system comprises: means for
establishing a water/liquid hydrocarbon interface in a three-phase
separator; means for measuring the water/liquid hydrocarbon
interface in the three-phase separator, wherein a water/liquid
hydrocarbon interface measurement signal results; means for
comparing the water/liquid hydrocarbon interface measurement signal
to a set point, wherein a comparison signal results; means for
reducing the flow into the three-phase separator of hydrocarbon
well fracture water when the comparison signal indicates the
water/liquid hydrocarbon interface is above the set point and for
increasing flow into the three-phase separator when the comparison
signal indicates the water/liquid hydrocarbon interface is below
the set point, wherein the increasing flow comprises hydrocarbon
well fracture water from and make-up water.
[0157] In at least one example, best seen in FIGS. 14A and 14B, the
means for establishing a water/liquid hydrocarbon interface
comprises a diaphragm wier 140, and, ideally, the oil-water
interface is established at the wier-bottom 140b. Controlled by
flow meters and control valves seen in FIGS. 15 and 16.
[0158] Referring now to FIG. 17, a more detailed example is seen of
the interface level control of a three phase, four material
separator is provided. As seen in the Figure, inlet flow of
flow-back water to the separator is measured by turbine meter
(FE-101)/transmitter (FT-101) and controlled by flow control valve
(FV-101) via flow controller (FIC-101). Make-up water inlet flow is
measured by orifice plate (FE-103)/dP transmitter (FT-103) and
controlled by flow control valve (FV-103) via flow controller
(FIC-103). Water outflow is measured by orifice plate (FE-102)/dP
transmitter (FT-102) and controlled by flow control valve (FV-102)
via flow controller (FIC-102). The oil and water interface level in
the separator is measure by magnetic level gauge (LG-100) and also
by continuous capacitance level transmitter (LT-100). Both level
devices are mounted on an external level bridle made up of 2 inch
diameter pipe. The bridle comprises manual valves (HV-1, HV-2,
HV-3, HV-4, HV-5, HV-6, HV-9, and HV-10) for maintenance on the
bridle and attached instrumentation as will occur to those of skill
in the art. HV-1 and HV-2 are used to isolate the bridle from the
process. HV-3 and HV-4 are used to drain and vent the bridle
respectively. HV-5 and HV-6 are used to isolate the level gauge
from the process. HV-9 and HV-10 are used to isolate the level
transmitter chamber from the process. Each instrument on the bridle
is equipped with valves for maintenance. HV-7 and HV-8 are a part
of the level gauge and are used to drain and vent the level gauge
respectively. HV-11 is a part of the level transmitter chamber and
is used to drain the chamber.
[0159] The water/liquid hydrocarbon interface (aka "oil/water
interface") level in the separator is maintained by level
controller (LIC-100) with cascade control to flow-back inlet flow
controller (FIC-101), make-up water inlet flow controller (FIC-103)
and water outflow controller (FIC-102). Cascade control is
accomplished by the level controller sending a remote set point
(RSP) to the associated flow controllers and resetting their set
points to maintain interface level.
[0160] All controllers are set for steady state condition to
maintain normal liquid level (NLL=50%). Set points for individual
controllers are determined by desired capacity and separator
sizing.
[0161] In one operational example, as the interface level
increases, the level controller resets the water outflow controller
to throttle open while resetting the flow-back inlet flow
controller to throttle back to maintain normal liquid level. An
high liquid level (HLL=80%) alarm is triggered from an interface
level transmitter analog signal to an operator, allowing the
operator should take appropriate actions to regain control of the
interface level or operating conditions.
[0162] As interface level decreases, the level controller resets
the water outflow controller to throttle back while the resetting
flow-back inlet flow controller to throttle open to maintain normal
liquid level. If interface level decreases to a low liquid level
(LLL=10%), the system places the make-up water flow controller on
cascade control from the interface level controller by software
switch LX-100.
[0163] It should be kept in mind that the previously described
embodiments are only presented by way of example and should not be
construed as limiting the inventive concept to any particular
physical configuration. Changes will occur to those of skill in the
art from the present description without departing from the spirit
and the scope of this invention. Each element or step recited in
any of the following claims is to be understood as including to all
equivalent elements or steps. The claims cover the invention as
broadly as legally possible in whatever form it may be utilized.
Equivalents to the inventions described in the claims are also
intended to be within the fair scope of the claims. All patents,
patent applications, and other documents identified herein are
incorporated herein by reference for all purposes.
* * * * *