Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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CENTRAL PROCESSING FACILITY, DIRECT CONTACT STEAM GENERATION
OPTIMIZATION
FIELD OF THE INVENTION
[0001]
Embodiments of the present disclosure relate generally to a method,
apparatus and system for the optimization of an unconventional oil recovery
Central
Processing Facility (CPF) for the cost effective and efficient implementation
of a
Direct Contact Steam Generation (DCSG) system which is preferably located at
the
well pad.
BACKGROUND AND RELATED ART
[0002] Direct
Contact Steam Generators (DCSGs) are relatively new and not
well accepted in steam assist gravity drain (SAGD), Steam Flood (SF) and
Cyclic
Steam Stimulation (CSS) heavy oil recovery. Great headway is being made in the
implementation and acceptance of this technology into the SAGD world. DCSG
systems, such as the Advanced Petro Technologies CEDSTM system have the
possibility of revitalizing the Canadian SAGD market. It will have a positive
influence on any unconventional oil recovery process that requires steam.
There is
much filed art relating to unconventional oil recovery and DCSG technology.
There
is also much already filed art specifically on CEDSTM steam generation
technology.
In all cases of DCSG there is a direct relationship to the efficient
implementation of
this new technology and the support of this technology from a CPF design.
Conventional SAGD CPF's with Once Through Steam Generators (OTSGs) are huge
and complex facilities. The majority of capital expenditure (Capex) and
operating
expenditure (Opex) related to the unconventional oil recovery process is spent
at
the conventional CPF. Much related art has been filed to optimize the
conventional
SAGD CPFs.
BRIEF SUMMARY
[0003] Various
embodiments of the present disclosure can include a system.
In some embodiments, the system can include a hydrocarbon production site. In
some embodiments, the system can include a direct contact steam generator
(DCSG) system. The DCSG system can be configured to generate steam and
supply the steam to an unconventional oil recovery process. The DCSG system
can
reside in close proximity to the hydrocarbon production site. The DCSG system
can include a DCSG boiler to which feedwater is provided, the feedwater being
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treated and supplied to the DCSG system from a remote central processing
facility
(CPF).
[0004] Various embodiments of the present disclosure can include a
system.
In some embodiments, the system can include a hydrocarbon production site. In
some embodiments, the system can include a DCSG system. The DCSG system
can be configured to generate steam and supply the steam to an unconventional
oil
recovery process. The DCSG system can reside in close proximity to the
hydrocarbon production site. The DCSG system can include a DCSG boiler to
which
feedwater is provided, the feedwater being treated and supplied to the DCSG
system at a location proximate to a location of the hydrocarbon production
site.
[0005] Various embodiments of the present disclosure can include a
system.
In some embodiments, the system can include a hydrocarbon production site. In
some embodiments, the system can include a DCSG system. The DCSG system
can be configured to generate steam and supply the steam to an unconventional
oil
recovery process. The DCSG system can reside in close proximity to the
hydrocarbon production site. The DCGS system can include a DCSG boiler to
which
feedwater is provided, the feedwater being treated and supplied to the DCSG
system at a location in close proximity to a location of the hydrocarbon
production
site, wherein the feedwater is not treated or supplied via a central
processing facility
(CPF).
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] Fig. 1 depicts a simplified schematic representation of a SAGD
CPF, in
accordance with embodiments of the present disclosure.
[0007] Fig. 2A depicts an example of a new CPF optimized for a DCSG
well,
pad, or series of pads configuration, in accordance with embodiments of the
present
disclosure.
[0008] Fig. 2B depicts an example of a new well, pad, or series of
pads
optimized for a DCSG configuration that compliments the CPF in Fig. 2A, in
accordance with embodiments of the present disclosure.
[0009] Fig. 3A depicts an example of another new CPF optimized for a
DCSG
well, pad, or series of pads configuration, in accordance with embodiments of
the
present disclosure.
[0010] Fig. 3B depicts an example of another new well, pad, or series
of pads
optimized for a DCSG configuration that compliments the CPF in Fig. 3A, in
accordance with embodiments of the present disclosure.
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DETAILED DESCRIPTION
[0011] Embodiments of the present disclosure relate generally to a
method,
apparatus and system for the optimization of an unconventional oil recovery
Central
Processing Facility (CPF) for the cost effective and efficient implementation
of a
Direct Contact Steam Generation (DCSG) system which is preferably located at
the
well pad. The CPF could be configured for a Steam Assisted Gravity Drain
(SAGD)
unconventional oil recovery process.
[0012] Conventional SAGD CPF's are jokingly known as "a huge and
expensive water treatment plant with a small oil well attached to them." This
unfortunate case is directly a result of using conventional OTSG units. These
steam generation units need very clean boiler feedwater to survive. They also
need the enormous and expensive support systems to generate the clean boiler
feedwater. Because of these requirements, the once through steam generators
are typically placed in the CPF. Unfortunately, this placement can make the
steam
generators miles away from the hydrocarbon wells they serve. Steam does not
travel well and it loses its energy quickly when shipped through a pipe. This
significantly adds to the cost of using the generated steam for unconventional
oil
recovery.
[0013] Steam generation capacity at a conventional CPF is typically
greater
than 80,000 barrels per day (bpd). This is partially due to the need to
amortize
through production volume the enormous cost and effort of producing acceptably
clean boiler feedwater for the conventional boilers.
[0014] DCSGs are today considered unconventional boilers. They are
preferably located at a hydrocarbon production site, such as a well, or pad,
or at
least close to a number of pads. A pad can be a collection of wells. At one of
these
locations, steam can be used directly or in a worst case scenario, the steam
may
have to travel a minimal distance. DCSGs can operate on dirty water and for
the
most part eliminate the "huge water treatment plant" requirement from the CPF.
This new paradigm shift presents opportunities to re-think the CPF design and
its
function to optimize it for DCSG technology. At least 2 approaches to apply
this
new technology are possible. Embodiments of the present disclosure include
methods, apparatus, and systems to optimize the CPF for DCSG applications. In
these preferred applications the DCSGs will be placed close to the wells. In
an
example, a steam outlet conduit associated with the DCGSs can be less than one
mile in length. In some embodiments, the steam outlet conduit associated with
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the DCGs can be at the hydrocarbon production site (e.g., well), effectively
placing
the steam outlet conduit zero feet away from the oil production site. In some
embodiments, the steam outlet associated with the DCGS can be up to two miles
away from the oil production site.
[0015] At this ideal location, close to the wells, the DCSG system
can be
configured to produce as small as 1,000 bpd of steam and can serve a single
well.
In some embodiments, the DCSG system can be configured to produce as large as
50,000 bpd, if the system serves a number of closely positioned pads that
require
high volumes of steam. One of the advantages of the embodiments of the present
disclosure is that the CPF can now be located any reasonable pipe line
distance away
from the wells and pads. For example, the CPF can be located remotely from the
hydrocarbon production site and/or the DCSG. In some embodiments, the CPF can
be located a distance from the oil production site in a range from 10 miles to
100
miles, although embodiments are not so limited and the CPF can be located
closer
than 10 miles or further than 100 miles from the oil production site. This
allows for
a homologation of water and oil services and an economy of scale that could
support
a very large CPF. With the disclosed technology, the CPF could service over
100,000 bpd of unconventional oil which would equate to a conventional CPF
that
previously would have had to produce over 300,000 bpd of steam. This disclosed
large CPF could be contained at one location and be third party operated by a
service provider who sells the CPF services to a producer or a number of
producers.
This configuration would again reduce the Opex of the unconventional oil
recovery
process.
[0016] Steam Flood applications and Cyclic Steam Stimulation
applications
are similar in most respects, but are typically less demanding than SAGD. For
that
reason, this disclosed art will refer primarily to a SAGD application, which
will cover
the other simpler unconventional applications by default. In all cases, a
better way
of optimizing the current CPF is needed. As a result of the resources involved
with
the operation of the current CPF, if improvements are not made to the current
CPF
design, Opex and Capex associated with the current CPF design may lead to the
downfall of much of the unconventional oil industry. Embodiments of the
present
disclosure provide a better, more cost-effective way, in terms of both Opex
and
Capex when implementing a CPF that is optimized for a DCSG system. When
DCSG systems are coupled with this new optimized CPF technology it results in
offering competitive relief to the beleaguered unconventional oil industries
such as
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the Canadian SAGD market. In essence, by utilizing this new technology the
industry will get a "new lease on life".
[0017] Fig. 1 depicts a SAGD CPF, in accordance with embodiments of
the
present disclosure. The steam boiler 1 is typically an OTSG, but could also be
a
drum boiler or other conventional boiler design. A DCSG could also be used at
the
CPF in place of an OTSG at the drawn location but it could compromise the
efficiency
of the complete system due to steam transportation losses to the pads if
located in
the CPF. Steam traveling through a steam conduit 2, which is fluidly coupled
with
the steam boiler 1, is produced by the steam boiler 1. The steam that is
transported to the pads via the steam conduit 2 is to be injected into the
SAGD
wells. In some cases, the wells could be over five miles away from the steam
generator. Significant system energy losses, sometimes over 10%, can be
suffered due to shipping the steam these long distances. A natural gas feed
conduit 3 is fluidly coupled to the steam boiler 1 and can carry natural gas
or natural
gas plus a produced gas fuel supply to the steam boiler 1. A waste water
conduit 5
contains the blow down waste water required to maintain the health of the
conventional boiler. In some embodiments, a boiler feedwater (BFW) conduit 4
contains the boiler feedwater provided to the steam boiler 1 and is fluidly
coupled to
the steam boiler 1. The boiler feedwater is buffered in a storage tank 8,
which is
supplemented in its supply of clean and treated boiler feedwater from clean
and
treated makeup feedwater provided to the storage tank 8 via the makeup
feedwater
conduit 7. The feedwater is manufactured from returned produced water, which
is
provided from a bitumen treating and separation plant 16 to a water treatment
plant 9 via a produced water conduit 19. The returned produced water, as the
name implies, is water returned from the bitumen well. The dirty produced
water
provided to the water treatment plant 9 via the produced water conduit 19 goes
through an extensive clean up and filtering process in the water treatment
plant 9
that makes up the majority of the CPF. For simplicity, the water treatment
plant 9
is diagrammatically shown in Fig. 1. The water treatment plant can produce
waste
water, lime sludge and cake, which are depicted as exiting the water treatment
plant 9 via waste conduit 10. In some embodiments, the feedwater provided to
the
boiler 1 can be treated and supplied to the boiler at a location in close
proximity to
a location of the hydrocarbon production site.
[0018] Bitumen emulsion and produced gas arrive from the pad via
production conduit 15. The mix is processed and separated via separation
system
16, which can be made up of components such as one or more of a Free Water
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Knockout systems, skimmer (e.g., skim tank), and gas separation systems. The
produced gas can be provided to a treatment system 18 via a produced gas
conduit
17. The treatment system 18 can clean up the produced gas, which can be re-
used
in the boilers (e.g., steam boiler 1) and pads. As previously discussed,
semi-processed produced water can be shipped to the water treatment process or
"plant" as shown as water treatment plant 9.
[0019] Some diluent from diluent storage tank 20 may be injected into
the
bitumen separation system 16 through a first diluent conduit 21. The reduced
viscosity bitumen is transported through bitumen conduit 22, which may need
additional amounts of diluent added to become Dilbit or salable product, as
shown in
hydrocarbon storage and handling tank 24. The Dilbit or salable product can be
transferred through hydrocarbon conduit 23 into the hydrocarbon storage and
handling tank 24. The Dilbit or salable product can be pumped from the
hydrocarbon storage and handling tank 24 via a pump 25 and finally exit via
exit
conduit 26 to a sales pipeline, in an example.
[0020] Electrical power is shown as power 6, which would be used to
power
the CPF and the pads. The source of the power 6 can be from an on-site
generator
and/or electrical transmission line connected to a power plant. A carbon-based
fuel and blanket and lift gas can be received from the CPF via a gas conduit
13. In
some embodiments, conduit 11 is used to provide a method to premix preferred
amounts of well head gas into natural gas supply 12, which can be in
communication with conduit 13. In some embodiments, conduit 14 can contain a
non-natural gas, mixed but treated well head gas, to potentially be used as a
blanket gas or other hydrocarbon recovery tool. Basic subsystems such as
glycol
loops and condensate systems have not been shown to aid in clarity.
[0021] Fig. 2A is an example of a new CPF optimized for a DCSG well,
pad or
series of pads configuration, in accordance with embodiments of the present
disclosure. Similar elements, such as those depicted and discussed with
respect to
Fig. 1 are denoted with a "prime" symbol in Fig. 2A. For example, the produced
gas
treating facility 18, as depicted in Fig. 1, can include the same or similar
features
with respect to the produced gas treating facility 18', as depicted in Fig.
2A. In
contrast to Fig. 1, Fig. 2A depicts an embodiment that includes a minimal
water
treatment system 27. In some cases, the minimal water treatment system can
include just a coarse filter. The source of DCSG boiler feedwater provided to
the
minimal water treatment system 27 via the produced water conduit 19' could
come
directly from the Free water Knockout or from an additional downstream skim
tank,
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which can be included in the separation system 16'. Neither of these devices
are
shown in Fig. 2A for simplicity. The lightly (e.g. minimally) treated water
then
travels through treated water conduit 30 into a dirty feedwater storage tank
28 and
is transported through a boiler feedwater conduit 29 to the well, pad, or pads
to be
consumed by the DCSG. As generally referred to herein, the well, pad, and/or
pads can be referred to as a hydrocarbon production site. The make-up
feedwater
in conduit 7' could be fresh, dirty or contaminated water, or pond water from
a
bitumen mining operation.
[0022] Fig. 2B depicts an example of a new well, pad, or series of
pads
optimized for a DCSG configuration that compliments the CPF in Fig. 2A, in
accordance with embodiments of the present disclosure. Similar elements, such
as
those depicted and discussed with respect to Fig. 1 are denoted with a "prime"
symbol in Fig. 2B. For example, the electrical power 6, as depicted in Fig. 1
can
include the same or similar features with respect to the electrical power 6',
as
depicted in Fig. 2B. The electrical power 6' can be received from the CPF.
Carbon-based fuel and blanket and lift gas 13' can be received from the CPF. A
DCSG system 31 can be located at a well, pad or in close proximity to pads and
the
deployment of the generated steam via generated steam conduit 32. In some
embodiments, the steam outlet conduit associated with the DCGs can be at the
hydrocarbon production site (e.g., well), effectively placing the steam outlet
conduit
zero feet away from the oil production site. In some embodiments, the steam
outlet associated with the DCGS can be up to two miles away from the oil
production
site.
[0023] Generated steam conduit 32 transfers steam generated by the
DCSG
system 31 to three closely positioned pads (pads not shown), although
embodiments are not so limited. For example, the generated steam conduit 32
could be sized to only service one well or many wells or a single pad or many
pads.
The key to keeping a high efficiency and minimizing both Capex and Opex would
be
to minimize the steam losses by minimizing the distance the steam is required
to
travel through careful DCSG system 31 placement versus deploying the minimum
amount of DCSG systems required to complete the desired unconventional oil
recovery. A waste conduit 33 could be used to eject the waste solids from the
produced water if superheat were used in the DCSG system 31 or blowdown waste
conduit 34 could be used to eject blowdown if saturated steam conditions were
generated in the DCSG system 31. A boiler feedwater conduit 29 delivers Boiler
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Feedwater from the CPF to the DCSG system 31. A production conduit 15' carries
the bitumen emulsion from the well producer back to the CPF.
[0024] Fig. 3A
depicts an example of another new CPF optimized for a DCSG
well, pad, or series of pads configuration, in accordance with embodiments of
the
present disclosure. Similar elements, such as those depicted and discussed
with
respect to Fig. 1 are denoted with a "double-prime" symbol in Fig. 3A. For
example, the electrical power 6, as depicted in Fig. 1 can include the same or
similar
features with respect to the electrical power 6", as depicted in Fig. 3A. The
CPF in
Fig. 3A is similar to the CPF depicted in Fig. 2A with the exception that the
Bitumen
Treating and Separation system (e.g., see 16' in Fig. 2A) has been removed
from
the CPF and reproduced at the well, pad, or series of pads as shown in Fig.
3B. The
larger CPF based separation system would most likely be reproduced with a
higher
quantity of smaller separation systems at the well, pad, or series of pads.
[0025] Fig. 3B
depicts an example of another new well, pad, or series of pads
optimized for a DCSG configuration that compliments the CPF in Fig. 3A, in
accordance with embodiments of the present disclosure. In an example, Fig. 3B
depicts a well, pad or series of pads that is configured to be served by the
CPF in Fig.
3A. Elements denoted by power 6", makeup feedwater conduit 7", gas conduit
13", production conduit 15", separation system 16", first diluent conduit 21",
DCSG
system 31', generated steam conduit 32', waste conduit 33', blowdown waste
conduit 34', serve the same functions already disclosed in the previous
figures and
are denoted by a "prime" symbol or a "double-prime". As depicted, a first
diluent
conduit 21" carries diluent which is provided from the CPF described in Fig.
3A.
The diluent may be used to thin the bitumen in separator 16" or added to the
already separated bitumen in conduit 36. Produced gas can be transferred to
the
DCSG system 31' via produced gas conduit 45. Pump 37 is used to move the
Dilbit
through conduit 36 to a pipeline or storage area. Separated boiler feedwater
is
sent in conduit 40 through boost pump 38 to coarse filter 39. The boiler
feedwater
is buffered in a buffer tank 41, where overflow conduit 44 and pump 43 and
make-up inflow water in makeup feedwater conduit 7" are used to maintain the
correct level in buffer tank 41. For example, make-up inflow water can be
introduced into buffer tank 41 via makeup feedwater conduit 7" and/or water
can be
extracted from the buffer tank 41 via the overflow conduit 44 and pump 43 to
control the level of water in the buffer tank 41. The make-up feedwater in
conduit
7" could be fresh, dirty or contaminated water, or pond water from a bitumen
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mining operation. Feedwater from tank 41 is transferred and pressurized by
pump
42 into the DCSG system 31'.
[0026] Although multiple embodiments have been described above with a
certain degree of particularity, those skilled in the art could make numerous
alterations to the disclosed embodiments without departing from the spirit or
scope
of this disclosure. All directional references (e.g., upper, lower, upward,
downward, left, right, leftward, rightward, top, bottom, above, below,
vertical,
horizontal, clockwise, and counterclockwise) are only used for identification
purposes to aid the reader's understanding of the present disclosure, and do
not
create limitations, particularly as to the position, orientation, or use of
the devices.
Joinder references (e.g., affixed, attached, coupled, connected, and the like)
are to
be construed broadly and can include intermediate members between a connection
of elements and relative movement between elements. As such, joinder
references do not necessarily infer that two elements are directly connected
and in
fixed relationship to each other. It is intended that all matter contained in
the
above description or shown in the accompanying drawings shall be interpreted
as
illustrative only and not limiting. Changes in detail or structure can be made
without departing from the spirit of the disclosure as defined in the appended
claims.
[0027] Any patent, publication, or other disclosure material, in
whole or in
part, that is said to be incorporated by reference herein is incorporated
herein only
to the extent that the incorporated materials does not conflict with existing
definitions, statements, or other disclosure material set forth in this
disclosure. As
such, and to the extent necessary, the disclosure as explicitly set forth
herein
supersedes any conflicting material incorporated herein by reference. Any
material, or portion thereof, that is said to be incorporated by reference
herein, but
which conflicts with existing definitions, statements, or other disclosure
material set
forth herein will only be incorporated to the extent that no conflict arises
between
that incorporated material and the existing disclosure material.
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