Note: Descriptions are shown in the official language in which they were submitted.
"SKIM TANK FOR TREATING PRODUCTION FLUIDS"
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] None
FIELD
[0002] Embodiments herein relate to improved apparatus and
methodologies for separating production water containing an oil-in-water
emulsion, the production water stemming from at least one primary separation
process following the recovery of oil during oil well production operations.
Specifically, the presently improved apparatus and methodologies provide a
large, continuous flow separation vessel for removing residual oil particles
from
pre-treated production water having less than 1% oil-in-water.
BACKGROUND
[0003] In oil field production operations, produced fluids are oil and
water
fluid mixtures that require specialized separation processing. It is desirable
to
separate the oil from the water so that the oil can be sold and the water can
be
re-used (e.g. re-injected back into the reservoir to maintain reservoir
pressures).
It is well known that the water recycled from the production fluid separation
processes must be of sufficient quality for re-injection, particularly where
the
water is mixed with polymers or other chemicals prior to the re-injection.
[0004] To date, however, existing separation processes prove
ineffective
because the produced oil-water mixture is often an emulsion that can be
difficult
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to separate, particularly where the emulsion contains additional production-
enhancing chemicals. Known processes also prove troublesome where the
produced oil-water mixtures contain sand or other debris (e.g. for production
from
fracked wells, it is common for 10 ¨ 15 cubic meters/month of sand to
accumulate during separation processes when producing 3000 ¨ 5000 BPD
fluid).
[0005] Skim tanks are very large gravity separation vessels that can
be
used to separate the oil from the water. Oil, having a lower density than
water,
rises to the surface of the water. During separation, oil droplets coalesce
together
and float to the top of the surface of the water, where it can be removed.
Many
attempts have been made over the past half century to improve the efficiency
of
skim tanks including, for example, configuring tanks to increase the tank's
residence or retention time, allowing more time for the oil to rise through
the
water. Empirical retention time, as opposed to theoretical retention time, is
commonly defined as the total amount of time that a molecule of fluid remains
in
the tank before exiting the tank. Other attempts to improve the efficiency of
skim
tanks have included modifying the tank to include different piping designs
such
as horns, nozzles, deflectors and/or accumulators to assist with the
separation.
[0006] More specifically, some existing tanks have been designed with
the
aim of providing a longer flow path for the production fluids to travel, such
flow
path often incorporating coalescing structures to enhance separation. For
example, as described in U.S. Patent No. 4,555,332, tanks have been configured
to form a continuous fluid flow channel through coaxially arranged cylindrical
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chambers formed by baffles within the tank. U.S. Patent No. 4,844,819
discloses
a vertical separation vessel specifically configured to enhance the overall
(plastic) surface area of the tank, such that oil, which has an affinity to
the plastic,
adheres thereto and coalesces into larger globules.
[0007] Other known tanks are designed to incorporate modified inlet piping
(e.g. conical-shaped inlet diffusers) that cause the fluid flow to achieve
greater
horizontal width when introduced to the tank, while minimizing vertical
divergence
(and thus turbulent mixing) of the fluid as it enters the tank.
[0008] To date, however, known skim tanks continue to fall short in
providing greater than approximately 50% of theoretical retention time at
best,
which is a result of water short-circuiting to the outlet nozzles and
decreasing
tank efficacy. As a result, many operators are forced to take additional
measures
to remove residual oil in the water, e.g. installing filters on the outlet
stream, or
adding additional tanks to increase overall retention time, such measures
increasing the overall costs of the separation process.
[0009] There remains a need for an improved system that proves
effective
at removing residual oil from production water resulting from primary
separation
processes following oil well production operations, particularly where the
resulting production water contains approximately 99% water. It is desirable
that
such an improved system alters the specific gravity and increases the particle
size of the oil phase within the production water, and also provides a
sufficient
actual (empirical) retention time (e.g. 50% and up to 80% of theoretical
retention
time) so as to efficiently and effectively perform the separation process.
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SUMMARY
[0010] According to embodiments herein, an improved system for
continuously de-oiling production water emanating from conventional oil field
production processes is provided.
[0011] Specifically, in some embodiments, methods are provided for
separating production water arising from at least one primary separation
process
following oil well production operations, the production water having at least
a
water phase and an oil phase between 100 to 10,000PPM oil-in-water, the
method comprising: receiving the production water in at least one gravity
separation vessel, wherein receiving the production water comprises
introducing
the received production water to the first fluid tank along the entire height
of the
first fluid tank, and then directing fluid flow along a first fluid flow path
within the
first fluid tank at a flowing velocity of approximately one foot per minute
(calculated over the entire cross-sectional area of the water flow path). Once
.. separated, the method comprises recovering the separated oil phase from the
at
least one first fluid tank and directing the separated water phase, via at
least one
fluid conduit, to the at least one second fluid tank, wherein receiving the
separated water phase comprises introducing the separated water phase to the
second fluid tank along the entire height of the second fluid tank, and
directing
fluid flow along a second fluid flow path within the second fluid tank at a
flow rate
of approximately one foot per minute. Again, once separated, the method
comprises recovering the separated oil phase from the at least one second
fluid
tank, and recovering the resulting separated water phase from the at least one
4
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second fluid tank, wherein the resulting separated water phase contains less
than approximately 50 PPM oil-in-water.
[0012] According to the present embodiments, the oil phase of the
production water received by the present system comprises heavy oil having a
specific gravity of at least approximately 0.90 ¨ 0.95. In some embodiments,
the
method further comprises injecting lighter oil into the production water to
reduce
the specific gravity of the heavy oil to at least approximately 0.75 ¨ 0.85.
The
present method may further comprise providing a mixer for enhancing the
distribution of lighter oil injected into the production water.
[0013] According to the present embodiments, the oil phase of the
production water received by the present system comprises oil particles
averaging approximately 10 ¨ 40 microns in size. In some embodiments, the
method further comprises providing a coalescing medium and exposing the
production water to the coalescing medium to increase the average oil particle
size to approximately at least 100 microns in size.
[0014] According to other embodiments, an apparatus is provided for
continuously separating production water containing an oil-in-water emulsion,
the
production water stemming from at least one primary separation process
following oil well production operations, the production water having at least
an
oil phase and water phase between 100 to 10,000PPM oil-in-water, the
apparatus comprising: at least one first fluid tank having at least one first
tank
inlet for receiving the production water from the at least one primary
separation
process, and at least one first tank outlet for expelling the oil phase
separated
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from the water phase in the first fluid tank; at least one second fluid tank
in fluid
communication with the first fluid tank, the second fluid tank having at least
one
second tank inlet for receiving the water phase from the at least one first
fluid
tank, and at least two second tank outlets for expelling the oil phase
separated
from the water phase and the resulting clean water from the second tank; and
at
least one fluid conduit providing fluid communication between the first and
second fluid tanks, and for directing the water phase from at or near a bottom
end of the first fluid tank to the second fluid tank at or near an upper end
of the
second fluid tank, wherein both the at least one first tank inlet and the at
least
one fluid conduit are configured to controllably regulate the flow of the
production
water through the first and second fluid tanks at an average cross-sectional
flowing velocity of one foot per minute, respectively. Moreover, the at least
one
first tank inlet and the at least one fluid conduits are also each configured
to
introduce the production water along the entire height of the first and second
fluid
tanks, respectively.
[0015] According to other embodiments, the at least one first and
second
fluid tanks may be substantially cylindrical, and the at least one first fluid
tank
may be concentrically nested within the at least one second fluid tank. Both
the
at least one first and second fluid tanks may further comprise at least one
impermeable baffle for directing fluid flow along an elaborate fluid flow
path. In
some embodiments, the apparatus may further comprise at least one coalescing
medium, at least one gas injection port, and at least one mixer.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0016] Figure 1 is a top view schematic of an improved gravity
separation
system comprising a gravity separation vessel according to embodiments herein,
[0017] Figure 2 is a cross-sectional side view schematic of the
gravity
separation vessel shown in Figure 1;
[0018] Figure 3 is a cross-sectional side view schematic depicting
fluid
flow patterns (F1/F2) within the gravity separation vessel shown in Figure 1,
according to embodiments herein;
[0019] Figure 4 is a schematic side view of a fluid conduit pipe for
transferring fluids between first and second tanks of the gravity separation
vessel
shown in Figure 1, according to embodiments herein; and
[0020] Figure 5 is a schematic diagram of at least one coalescing
medium,
and associated componentry, used in combination with the gravity separation
vessel showing in Figure 1, according to embodiments herein.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[0021] Following conventional oil and gas recovery operations, pumped
effluent recovered at the surface, known as "production fluids", must undergo
separation processes to separate the hydrocarbons from the aqueous phase.
Generally, primary separation processes produce oil and a water byproduct, the
water byproduct often containing residual oil and other contaminants (referred
to
as "production water"). Production water often contains less than 1% residual
oil
and generally comprises one of two forms, free water that quickly and easily
separates without significant intervention, or emulsified water where the oil-
in-
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water molecules are tightly bound and require further processing. In either
case,
subsequent separation processes are required in order to remove sufficient
residual oil from the production water that it can re-used (e.g. re-injected
into the
formation).
[0022] As would be known, the quality of production water can vary,
ranging from a large fraction of hydrocarbons, to barely-perceptible trace
amounts. There is a need for effective apparatus and methodologies for
treating
production water, even where the production water contains only trace amounts
of oil (e.g. less than 10,000PPM of oil, or less than 1% oil in water). For
example,
it is desirable that such apparatus and methodologies are operative to treat
production water such that the resulting fluids, following separation
processes,
can contain less than 50 PPM of oil in the treated production water.
[0023] Many factors can impact the separation of hydrocarbons from
production water including, without limitation, the stability or "tightness"
of the oil-
in-water emulsion, the temperature of the fluids, the primary separation
processes that have occurred to generate the production water (e.g. at the oil
field battery), etc. Specifically, as will be described in more detail below,
the
specific gravity of the hydrocarbons compared to the production water and the
particle size of the hydrocarbon within the production water, can also impact
.
separation processes. As such, in order to enhance the separation of oil from
oil-
in-water production water, the present apparatus and methodologies aim to both
alter the specific gravity of the oil within the production fluids, and to
increase the
oil particle size.
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[0024] Specific Gravity: The velocity at which oil will rise within
the
production water is largely dependent upon the differential between the
specific
gravity of the oil and the water. More specifically, oil having a specific
gravity of
less than 1.0 will typically rise in production water, which has a specific
gravity of
approximately 1.03. It has generally been observed that quantities of oil in
production water resulting from conventional primary separation processes can
be:
- for oil having a specific gravity of approximately 0.8 ¨ 1.0, the
production water contains approximately 1,000 ¨ 10,000ppm oil in
water,
- for oil having a specific gravity of approximately 0.6 ¨ 0.8, the
production water contains approximately 300 ¨ 1,000ppm oil in water.
As such, lighter oil (having a lower specific gravity) will typically separate
from
production water at a faster rate than heavier oil.
[0025] Droplet Size: The velocity at which the oil will rise in production
water is also largely dependent upon the droplet size of the oil in the water
(where larger droplets demonstrate increased buoyancy). As such, the rising
velocity of oil within produced water can increase considerably with larger
oil
particle size.
[0026] Retention Time: In addition to increasing the velocity at which the
oil separates from the production water, the separation processes can further
be
enhanced by prolonging the time allotted for the processes to occur. For
example, where the separation processes occur in gravity separation vessels,
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such as skim tanks, a "theoretical retention time" for the tank can be
calculated.
Herein, "theoretical retention time" means the total volume of fluids
contained
within the tank, divided by the flow rate of the fluids through the tank (as
expressed in minutes or hours). A theoretical retention time can be calculated
to
determine appropriate settling times for the fluids, wherein the longer the
retention time, the more effective the separation processes. Known skim tanks
used in the oil field to separate production water typically have a
theoretical
retention time of approximately forty five (45) minutes to two (2) hours (or
any
other such time as may be economical).
[0027]
Unfortunately, the calculated theoretical retention times for
separation tanks do not necessarily equate with the "actual or empirical
retention
times". Herein, "actual retention time" means the actual displaced volume of
fluids within the tank over a predetermined amount of time. Actual retention
times, which are commonly determined using a tracer dye during operations, are
known to be significantly less than the theoretical retention time. For
example,
the actual retention times for known skim tanks used to separate production
water are relatively poor, being anywhere from approximately as low as 5% to
as
high as 50% of the theoretical retention time. The resulting cleanliness of
the
fluids exiting known skim tanks is unacceptably low. Where the specific
gravity of
heavy oil entering the tank is 0.85 or higher, the quantity of oil remaining
in the
outlet water exiting the tank is often only reduced by approximately 30% - 50%
ppm compared to inlet water that was introduced to the tank. There is a need
for
an improved system for enhancing the separation of oil from production water
CA 3004676 2018-05-11
comprising an oil-in-water emulsion, wherein the system is operative to both
increase the buoyant velocity of the oil separation and to increase the actual
retention time allotted for the separation to occur.
[0028] According to embodiments herein, improved apparatus and
methodologies for separating the production water resulting from hydrocarbon
recovery from oil well production is provided, wherein the production water
has
undergone at least one primary separation process and comprises an oil-in-
water
emulsion having between 100 to 10,000PPM oil in the water. The present
apparatus and methodologies aim to enhance the separation processes of pre-
separated production water by increasing the rate at which the oil separates
from
the water (i.e. the aqueous phase), and the actual retention time allotted for
the
separation to occur. In some embodiments, the present apparatus and
methodologies aim to alter both the specific gravity and the particle size of
the oil
within the production water, and to provide an enhanced fluid flow path for
the
fluids to travel as they undergo gravity separation. In some embodiments, the
present apparatus and methodologies aim to provide for the continuous flow of
large amounts of fluids (e.g. up to at least 7,000 m3/d, which is equivalent
to at
least approximately 291.7 m3/hour or 1,284 GPM). Herein, "fluids" and
"production water" may be used interchangeably to refer to the pre-treated
production water feed stream introduced into, and treated by, the present
apparatus and methodologies. The present apparatus and methodologies will
now be described having regard to FIGS. 1 ¨ 5.
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[0029] Having regard to FIG. 1, an improved gravity separation vessel
10,
referred to interchangeably herein as a vessel or a skim tank, and methods of
using same are provided. According to embodiments, the present simple, yet
effective, gravity separation vessel 10 is configured to provide an arduous
fluid
flow path for fluids received therein, minimizing the short circuit of fluid
flow from
the inlet to the outlet of the vessel 10. Additionally, as will be described,
the
present gravity separation vessel 10 is configured to alter the specific
gravity of
components within the fluids (i.e. the oil phase of the oil-in-water
emulsion),
resulting in lighter components, and to alter the particle size of components
in the
.. fluids (i.e. the oil particles within the oil-in-water emulsion), resulting
in larger
components.
[0030] Having regard to FIG. 2, in some embodiments, the present
separation vessel 10 may comprise at least one (inner) fluid tank 12
concentrically nested within at least one second (outer) fluid tank 14.
Although
.. generally cylindrical tanks 12,14 are shown, it should be understood that
any
shape of tank operative to achieve the present methodologies is contemplated.
The presently cylindrical tanks 12,14 each comprise a sidewall, and a bottom
wall (i.e. it is contemplated that the tanks may or may not share a common
bottom wall). First tank 12 may or may not be open-topped, and second tank 14
comprises a top cover (as shown). It should be understood that vessel 10 may
be
enclosed via, for example, a gas blanket or any other known means of
preventing
contaminants from the environment (e.g. oxygen, which can cause bacterial
growth) from entering the vessel 10. As will be described, each fluid tank
12,14
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may comprise at least one fluid inlet for receiving fluids, and each fluid
tank 12,14
may have at least two fluid outlets, for expelling the separated fluid streams
from
the vessel 10. For example, each tank 12,14 may have at least one first outlet
for
expelling the oil phase separated out from the production water (e.g. skimmers
13), and at least one second outlet for expelling the cleaned water phase.
Separation vessel 10 may further comprise at least one fluid conduit 16 for
providing fluid communication between the first and second tanks 12,14. Tanks
12,14 may be large gravity separation vessels wherein, for example, first tank
12
may have a height of at least approximately 22 feet and an inner diameter of
at
least approximately 12 feet, and second tank 14 may have a height of
approximately 26 feet and an inner diameter of at least about 24 feet (e.g. an
overall fluid capacity of approximately 2000 bbl, or approximately 300 ¨ 350
m3).
[0031] In some embodiments, each of the first and second tanks 12,14
may be configured to further comprise at least one interior baffle 17,19 (see
FIG.
1). Baffle 17 may extend substantially across the cross-section of first fluid
tank
12, and may be substantially equal in vertical height to the tank 12. Baffle
17 may
be impermeable, such that fluids introduced into tank 12 must follow along a
first
wide fluid flow path circulating around baffle 17 (arrows F1). As such, in
some
embodiments, inlet 11 may be positioned in a manner to introduce fluids into
tank
12 on a first side of baffle 17, while fluid conduit 16 may be positioned on
the
opposite side of baffle 17 from inlet 11, such that fluids circulating around
baffle
17 exit first tank 12 via fluid conduit 16. It should be appreciated that
gravity
separation of the production water may continue during and throughout the
entire
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first fluid flow path (F1), such fluid flow path (F1) formed via a wide
channel
formed within tank 12 (e.g. at least about 5 ¨ 6 feet in width between the
inner
periphery of the tank sidewall and the baffle 17, and at least about 16 ¨ 18
feet
high, i.e. achieving a ratio of 3:1 height over width). The wide channels of
the
present system may be specifically designed so as to decrease the velocity of
fluid flow through the channel, minimizing turbulence and provide a quiet flow
of
fluid through the channel. It should further be appreciated that baffle 17 may
be
configured and/or positioned in any manner known in the art for directing
fluid
flow to restrict or minimize short circuiting of fluid flow (F1) through first
tank 12.
[0032] Baffle 19 may extend entirely across the annulus formed between
the inner shell of the tank 14 and the outer shell of tank 12, and may be
substantially equal in vertical height to tank 12. Baffle 19 may be
impermeable
and may impede or delay the flow of fluid around the entire annulus formed
between tank 12,14 (arrows F2). As such, in some embodiments, fluid conduit 16
may be positioned in a manner to introduce fluids into tank 14 on a first side
of
baffle 19, while at least one first outlet 18 in second (outer) tank 14 may be
positioned on the opposite side of baffle 19 from conduit 16, such that fluids
circulating around the annulus exit via outlet 18 without re-circulating. It
should
be appreciated that gravity separation of the production water may also
continue
during and throughout the entire second fluid flow path (F2), such fluid flow
path
(F2) formed via a wide channel formed within tank 14 (e.g. at least about 5 -
6
feet in width between the inner periphery of tank 14 and the outer sidewall of
the
first tank 12 nested therein). It should further be appreciated that baffle 19
may
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be configured and/or positioned in any manner known in the art for directing
fluid
flow to restrict or minimize short circuiting of fluid flow (F2) through
annulus
formed between tanks 12,14.
[0033] Having regard to FIG. 3, fluids may be introduced into first
and
second tanks 12,14 via inlet pipe 11 (i.e. into first tank 12) and fluid
conduit 16
(i.e. from first tank 12 into second tank 14). As above, a production water
feed
stream containing an oil-in-water emulsion may be introduced into first tank
12,
via inlet 11, at a controlled rate, wherein the rate may be based upon the
separation processes achieved by the vessel 10. In some embodiments, the
production water may be introduced into inlet pipe 11 at a volume of
approximately between 100 - 10,000 m3/day, and preferably in the range of
approximately 3500 m3/day to 6500 m3/day.
[0034] Inlet pipe 11 may be configured to receive and distribute the
production water along the entire height of the tank 12, and particularly in a
manner where a larger volume of the fluids are introduced at or near the
surface
of the fluids (i.e. at or near an upper end of tank 12). As will be described,
it is
contemplated that a larger volume of the production water introduced into
vessel
10 enter tank 12 via an upper end of inlet 11 (i.e. up to at least between 50
¨
100%, and potentially about 70% of the introduced fluids).
[0035] Having regard to FIG.3, in some embodiments, inlet pipe 11 may
be configured to pass through the sidewall of both second (outer) tank 14 and
first (inner) tank 12 at or near the bottom of the tanks 12,14. Inlet pipe 11
may
then be configured to extend upwardly within inner tank 12, and in some cases
CA 3004676 2018-05-11
along the inner surface of the tank's sidewall. In this regard, inlet pipe 11
may
comprise a first horizontal pipe section 11 a and a second vertical pipe
section
(riser) lib, the horizontal and riser sections 11 a,11 b connected by at least
one
elbow (fitting) section. Such a configuration causes inlet pipe 11 to form a
vertical
column for introducing production water into the inner tank 12 substantially
near
to the surface of the fluids (e.g. at a distance of within approximately 3 - 4
feet
from the surface level). Once introduced into the tank 12, the oil separating
from
the water phase may rise, due to gravity, to the surface of the fluids within
tank
12, and be removed therefrom via outlet 13. Outlet 13 may comprise a skimmer
system or other means for removing oil from the surface of water as may be
known in the art. It should be appreciated that although the presently
configured
inlet 11 advantageously disperses the production water into tank 12 in a
manner
that minimizes the distance the separating oil must travel through the water
to
reach the surface thereof, any inlet pipe capable of achieving same is
contemplated.
[0036] Vertical inlet pipe section 11b may be configured to provide a
plurality of apertures 20 for controllably distributing the production water
into tank
12, ensuring fluid flow (i.e. preventing dead water zones) without creating
undue
high velocity. Inlet pipe 11 may be configured to provide an internal diameter
large enough to provide a very low or negligible friction loss of production
water
flowing therethrough, such that inlet 11 may serve as a header. In some
embodiments, vertical (riser) inlet pipe section 11 b may comprise a plurality
of
holes distributed along its length, wherein more holes are positioned at or
near
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the top of pipe section 11b (e.g. approximately at least 60 ¨ 1 inch diameter
holes), the number of holes decreasing towards the bottom of pipe section 11b.
Apertures or holes 20 may be positioned about the periphery of pipe section
llb
so as to direct fluid flow into tank 12 (along fluid flow path F1). It would
be
understood by a person skilled in the art that the size, the shape, the
number,
and the positioning of the holes formed in the vertical pipe section 11 b may
be
based upon, and determined by, the capacity of the separation vessel 10 and
the
flow rates/volume of production water being introduced so as to optimize fluid
flow and retention rates within the tank 12.
[0037] Having regard to FIG. 4, as above, vessel 10 may comprise fluid
conduit 16 configured to direct the separated water phase from the first tank
12
to the second tank 14, and specifically to withdraw the clean water phase from
the bottom of the first fluid tank 12 and to disperse the water phase into the
second fluid tank 14 for further separation. In some embodiments, conduit 16
is
.. configured to transfer the "cleanest" separated water from the lowest point
of the
first fluid tank 12 (at or near the bottom wall of the tank) to the "least
clean" water
at or near the surface of the fluids in the second tank 14. In this regard,
and
similar to inlet 11, conduit 16 is configured to minimize the distance that
oil
droplets separating from the water phase of the production fluids must travel
.. before being removed from the tank 14. In this further regard, conduit 16
enables
the present separation system to perform a phase separation mid-stream of a
continuous fluid flow path Fl ,F2). It should be appreciated that the overall
fluid
flow from first tank 12 to second tank 14 is continuous, and that the transfer
of
17
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fluid from first to second tank 12,14 creates an arduous fluid flow path,
increasing
the overall actual retention time of the fluid within the vessel 10. The
apparatus
and methodologies described herein are for explanatory purposes only, and it
should be appreciated that any vessel configuration operative to achieve the
present results is contemplated.
[0038] In some embodiments, fluid conduit 16 may be configured to pass
through the sidewall of first tank 12 and into second (outer) tank 14 at or
near the
bottom of tank 14. Conduit 16 may extend upwardly within outer tank 14, and
may be positioned at or near the outer periphery of the sidewall of tank 12.
Specifically, fluid transfer conduit 16 may comprise a first vertical conduit
section
16a and a second vertical conduit section 16b, the two vertical sections
connected by at least one horizontal conduit section 16c and corresponding
elbow (fitting) sections. In this regard, fluid transfer conduit 16 may form a
vertical
column for introducing the separated water phase received from first tank 12,
into
second tank 14 at or near the surface of the fluids within outer tank 14 (e.g.
at or
near approximately 3 ¨ 4 feet from the surface level), minimizing the distance
oil
droplets must rise before being removed from the second tank 14. Similar to
the
first tank 12, any residual oil in the water phase may rise, due to gravity,
to the
surface of the fluids within tank 14, and removed therefrom via at least one
second outlet 13. Outlet 13 may comprise a skimmer system or any other form of
outlet operative to remove separated oil from the surface of water phase, as
may
be known in the art.
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[0039] Vertical transfer conduit section 16b may be configured to
provide a
plurality of apertures 22 for controllably introducing the production water
into tank
14, ensuring continued fluid flow (i.e., preventing dead water zones) without
creating undue high velocity. In some embodiments, vertical conduit section
16b
may comprise a plurality of holes (e.g. approximately at least 60 ¨ 1 inch
holes)
distributed along its length, wherein more holes are positioned at or near the
top
of the conduit section 16b, the number of holes decreasing towards the bottom
of
conduit section 16b. Apertures 22 may be positioned about the periphery of
conduit section 16b so as to direct fluid flow into tank 14 (along fluid flow
path
F2). It would be understood by a person skilled in the art that the size, the
shape,
the number, and the positioning of the holes 22 formed in the vertical conduit
section 16b may be based upon, and determined by, the capacity of the
separation vessel 10 and the flow rates/volume of production water being
introduced so as to optimize fluid flow and retention rates within the tank
14.
[0040] By way of example, where the flow rate of vessel 10 may be
approximately 3500 m3/day, the velocity of production water flowing through
each
aperture 20,22 of inlet pipe section 11 b can be calculated by dividing the
total
flow by the number of apertures 20 as follows:
a) Volume of water through each aperture:
3500 m3/day/60 holes = 58.33 m3/day (or 40.5 L/min)/hole
b) Velocity (through apertures 20,22) =
58.33 x 35.3 x 144 / 0.7854 x 1440 x 60 = 4.4 feet/sec
c) Velocity (average) along flow paths (F1 /F2):
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3500 x 35.3 / 103.5 x 1440 x 60 = 0.0138 feet/sec
(Equivalent to 0.83 feet/minute or 94 minutes to completely flow
along flow paths Fl /F2).
[0041] By way of further example, where the flow rate of vessel 10
may be
approximately 6500 m3/day, the velocity of production water flowing through
each
aperture 20,22 of inlet pipe section lib can be calculated by dividing the
total
flow by the number of apertures 20 as follows:
b) Volume of water through each aperture:
6500 m3/day/60 holes = 108.33 m3/day (or 75 L/min)/hole
b) Velocity (through apertures 20,22) =
108.33 x 35.3 x 144 / 0.7854 x 1440 x 60 = 8.1 feet/sec
c) Velocity (average) along flow paths (F1/F2):
6500 x 35.3 / 103.5 x 1440 x 60 = 0.0257 feet/sec
(Equivalent to 1.54 feet/min or 51 minutes to completely flow along
flow paths F1/F2).
[0042] As is known, Stokes Law may be used to determine the settling
(or
buoyant) velocities of small spherical particles of a different specific
gravity in a
fluid medium. It would be appreciated that oil entrained in production water
can
comprise smaller spherical particles (e.g. between 10 ¨ 40 microns) having a
lower specific gravity (e.g. less than 1.0) in order to rise in produced
fluids (water)
typically having a typical specific gravity of 1.03. According to embodiments
herein, the present apparatus may be used alone or in combination with further
processing operations, such processing operations aimed at increasing particle
CA 3004676 2018-05-11
size, altering (reducing) the specific gravity of the particles being
separated, or a
combination thereof.
[0043] Having regard to FIG. 5, the present gravity separation vessel
10
may further comprise at least one coalescing medium 30, for adhering with
small
micron particles of oil within the production fluids (i.e. to increase the
particle size
of the oil in the oil phase, enhancing separation of the particles from the
water
phase). In some embodiments, the at least one coalescing medium 30 may be
positioned anywhere within vessel 10 and/or within the feed stream of
production
water being introduced thereto. Coalescing medium 30, e.g. a fiberglass mesh
filter material or the like, may be operative to cause smaller particles of
oil to
adhere to the medium (via the natural oleophilic tendency of oil to bond onto
fiberglass), and to coalesce with each other in order to form larger particles
as
the production water contacts the medium 30 (arrows denote fluid flow). For
example, oil particles within the production water fluid stream may be within
the
range of approximately 10 ¨40 microns, but may increase to be within the range
of approximately 100 ¨ 200 microns upon adhering to the coalescing medium 30.
Once the particles have reached a particular size, the oleophilic bond they
have
to the mesh will be overcome by the water flow, and the coalesced particles
will
become dislodged from the medium 30 and swept back into the fluid stream (e.g.
into the inlet stream entering the separation vessel 10). As such, where
applied,
the present coalescing medium 30 may be used to increase the size of oil
particles within the production water fluid stream (e.g. before entering
vessel 10)
and thereby enhance their separation from the water as it flows along fluid
flow
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paths F1/F2, or both. It should be understood that the structure of coalescing
medium 30 may be sized and assembled in such a fashion so as to enhance the
coalescing of small oil particles and discharge them on the downstream side of
the medium as larger particles.
[0044] In some embodiments, the present at least one coalescing medium
30 may be configured to collect and adhere oil particles where the production
water flows past the medium 30 at relatively low rates (e.g. less than 2 feet
per
second), and where a low differential pressure exists under normal design flow
rates. In some embodiments, the medium 30 may have a center portion
comprised of a woven fiberglass mesh, or the like, to provide a vast number of
individual oleophilic strands for capturing the 10 ¨ 40 micron-sized oil
particles.
On either side of the fiberglass mesh, known wedge wire mesh screens may be
positioned and specifically designed to block the entrance of large
sand/debris
from entering the medium 30 and plugging medium 30. The design of the wedge
wire screen only allows very small particles of debris to pass through it,
thus
reducing the risk of plugging the fiberglass mesh. Any small particles that do
get
through the inlet screen will be able to pass through the fiberglass mesh and
be
swept out of the downstream screen. Each mesh screen is mechanically
supported within valve 32 and capable of withstanding the designed pressure
drop should full blockage occur on the wedge wire screens. The differential
pressure across medium 30 may, at any time, be increased due to unwanted
debris (e.g. sand, grit, sludge or fibrous fragments) clogging or caking up on
the
inlet screen of medium 30. Where the differential pressure across the
coalescing
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medium 30 increases to a predetermined threshold, the coalescing medium 30
may be configured to "self-clean", releasing any debris that may have caked up
on the inlet of the coalescing medium 30 by reversing the coalescing medium
within the valve and thereby reversing the flow of the production water
through
the medium 30. For example, the at least one coalescing member 30 may be
positioned within a valve 32, such as within the ball of a ball valve, and the
rate of
fluid flow across the medium 30 may be monitored and controlled. In some
embodiments, the mesh portion of medium 30 may be configured to be
positioned inside the ball valve 32, thereby optimizing the velocity inside
the
mesh, such that the water sweeps off oil particles from the fiberglass strands
once the particles reach the sufficient size. Where the differential pressure
(measured, for example, via a differential pressure transmitter 33 operatively
connected to record signals from pressure sensors located up- and down-stream
of valve 32, referred to as Pi ,P2, respectively) reaches a maximum threshold,
a
motor 34 may be activated to rotate valve 32 at least 180 degrees, causing the
caked up debris that was formed on the inlet side of medium 30 to now be
turned
180 degrees and released from the outlet (downstream) of 30. Each of the
differential pressure transmitter 33 and motor 34 may be automated and
controlled via a programmable logic controller (PLC) 35.
[0045] Having further regard to FIG. 5, the present vessel 10 may
optionally comprise a gas port 36, e.g. a gas injection (blast) port,
operatively
connected to the feed stream of production water for introducing gas into the
stream. In some embodiments, the gas port 36 may be upstream of the at least
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CA 3004676 2018-05-11
one coalescing medium 30, such that the injected gas may serve to assist in
cleaning the medium of caked debris adhered thereto. Gas port 36 may be used
to create turbulence within the production water in a manner to de-cake debris
from the medium 30. Gas port 36 may be used as desired, or so as to inject gas
into the production water at the time, or immediately after, the at least one
medium 30 has been rotated by motor 34. In some embodiments, the blast port
36 may be automatically controlled, and may inject gas for a short duration of
time, such as less than 5 second and preferably between 1 ¨ 3 seconds. Gas
injected for 1 ¨ 3 seconds into port 36 may be adjusted in rate so as to
create
sufficient turbulence across medium 30 to remove all caked up debris that has
now been rotated to the downstream side of medium 30. Debris can then flow
along with the production water feed stream for separation therefrom within
vessel 10.
[0046] In some embodiments, the production water feed stream
introduced
into the present vessel 10 may comprise heavy oil, or oil having a specific
gravity
of approximately 0.95 or greater. It has been observed that lighter oil having
a
specific gravity of approximately 0.8 ¨ 0.85 or less rises up to 18 times
faster
than heavier oil (where the production water has a specific gravity of 1.03).
As
such, in some embodiments, the present vessel 10 may optionally further
.. comprise at least one injection port 38, for injecting, where desired,
lighter oil
particles having lower specific gravity than the heavy oil in the feed stream
(e.g.
lighter hydrocarbons having a specific gravity of approximately 0.6 ¨ 0.8)
into the
production water feed stream. Injection of oil having lower specific gravity
via
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CA 3004676 2018-05-11
injection port 38 may be dispersed via, for example, nozzle 39. In some
embodiments, nozzle 39 may be sized to atomize the lower specific gravity oil
into smaller particles (e.g. particles having a size of at least approximately
40
microns). Accordingly, in some embodiments, the oil phase of the production
water introduced into the present system 10 may comprise heavy oil having an
initial specific gravity of at least approximately 0.90 ¨ 0.95. In other
embodiments, and where lighter oil is injected into the production water to
reduce
or alter the specific gravity of the heavy oil, the oil phase of the
production water
introduced into the present system 10 may comprise a specific gravity of
approximately 0.75 ¨ 0.85.
[0047] Having further regard to FIG. 5, in some embodiments, the
present
vessel 10 may optionally further comprise at least one fluid mixer, such as
static
mixer 37, to enhance mixing and distribution of the lighter specific gravity
oil
being injected such that the entire production water feed stream being
introduced
into the vessel 10 has dispersed particles of the lighter oil in its entire
cross
section, thereby impacting or ensuring contact with the full cross sectional
area of
the coalescing mesh 30. Without being limited to theory, once lighter oil
particles
(e.g. having a specific gravity of approximately 0.6 ¨ 0.8) adhere to the mesh
30,
the particles join and mix with heavier oil particles in the feed stream (e.g.
having
a specific gravity of approximately 0.95 or greater), which also adhere to the
mesh 30, thereby creating a mixture of light and heavy oil particles,
resulting in
an oil particle having a reduced overall specific gravity. As above, these oil
CA 3004676 2018-05-11
particles having reduced specific gravity are swept through the coalescing
mesh
30 and enter vessel 10.
[0048] As a
result, the present system advantageously allows for the
resultant specific gravity to be predetermined and controlled by the amount of
light oil injected into the production water feed stream. As all lighter oil
specific
gravity particles are of particular (sufficient) size, they will adhere to the
coalescing mesh 30 and dilute the heavy oil particles clinging to the same
coalescing mesh 30. Thus, the amount of dilution desired (i.e. specific
gravity of
the mixture) can be controlled by regulating the amount of lighter oil
injected
through injection port 38 and corresponding nozzle 39 in comparison to the
amount of heavy oil produced in the inlet water stream. By way of example, and
without limitation, a quantity of 0.95 specific gravity oil mixed with an
equal
quantity of 0.7 specific gravity oil will result in two times the quantity of
oil with an
overall reduced specific gravity of 0.825.
[0049] According
embodiments herein, and by way of non-limiting
example, it is contemplated that the present apparatus and methodologies may
be used alone or in conjunction with an existing system of tanks or surface
equipment for separating and measuring oil, gas and water (e.g. an existing
oil
battery). In this regard, the present apparatus and methodologies may be used
to
improve the performance, safety and reliability of existing oil batteries, or
such
facilities may be retrofitted and/or replaced therewith. Where desirable, the
existing oil field battery may be modified such that the water injection plant
and/or
filtering skid is retrofitted or replaced to first accommodate polymer
injection, and
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CA 3004676 2018-05-11
then to accommodate the increased water injection capacities of the present
system (up to at least - 6500 m3/d).
[0050] In some cases, one or more of supplementary fluid vessels 10
may
further be added to the system, the additional vessels 10 as described herein,
where one or more of the vessels 10 may comprise a skim tank and one or more
of the vessels 10 may comprise an injection tank. As would be known, in
addition
to the additional vessels 10, any and all corresponding system componentry,
tie-
ins or ancillary equipment necessary to accommodate the vessels 10 would be
included such as, for example, a potential vapour recovery unit (VRU), a flare
system, and/or oil emulsion heating equipment. In addition to the present
capacity assessments, it would be understood that a review of the battery's
heat
transfer or other systems may be performed, in order to mitigate any potential
issues, including the possibility of polymer returns in future production
fluids
caking onto fire tubes. It would be understood that the at least one
additional fluid
.. vessels 10 may be sized and configured to be operative with the existing
oil field
battery, and also to compensate for a pump failure or a shutdown of the
existing
system, providing additional time to address or to troubleshoot a system
failure
(or potentially to arrange for a back-up truck service, if required).
[0051] It is contemplated that the one or more supplemental fluid
vessels
10 may be distinct or continuous in operation with the existing system. As
would
be understood, the fluid levels within the tanks may be maintained by one or
more control valves or pumps. Optionally, and where necessary, source water
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CA 3004676 2018-05-11
may be added directly to the injection tank in order to compensate for any
shortfall of required water for polymer makeup or voidage in the reservoir.
[0052] Although a few embodiments have been shown and described, it
will be appreciated by those skilled in the art that various changes and
modifications can be made to these embodiments without changing or departing
from their scope, intent or functionality. The terms and expressions used in
the
preceding specification have been used herein as terms of description and not
of
limitation, and there is no intention in the use of such terms and expressions
of
excluding equivalents of the features shown and the described portions
thereof.
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