Note: Descriptions are shown in the official language in which they were submitted.
CA 2962834 2017-03-30
FRONT TO BACK CENTRAL PROCESSING FACILITY
FIELD OF THE DISCLOSURE
[0001] Embodiments disclosed herein relate generally to systems and
processes for
water treatment, stream generation and waste treatment associated with
enhanced oil
recovery processes.
BRIEF DESCRIPTION OF DRAWINGS
[0002] Figures 1-6 are simplified block flow diagrams of a cyclic steam
stimulation
central processing facility (CSS-CPF) according to embodiments herein.
[0003] Figures 7-14 are simplified block flow diagrams of a steam assisted
gravity
drainage central processing facility (SAGD-CPF) according to embodiments
herein.
[0004] Figure 15 is a simplified block flow diagram of a comparative
process for
generating steam.
[0005] Figures 16-19 illustrate simplified block flow diagrams of
facilities retrofitted
or debottlenecked to incorporate the front to back central processing
facilities
according to embodiments herein.
SUMMARY OF CLAIMED EMBODIMENTS
[0006] In one aspect, the present application is directed toward a front-
to-back central
processing facility. The front-to-back central processing facility may include
an
inlet for receiving an oil-water emulsion from an enhanced oil recovery
system, the
emulsion comprising one or more of dissolved solids, entrained gases and/or
light
hydrocarbons, distillate and/or heavier hydrocarbons, and water. A gas-oil-
water
separation system may be used for separating the entrained gases and/or light
hydrocarbons from the oil-water emulsion, producing a vapor stream and an oil-
water stream. A deoiling system is provided for separating the oil-water
stream into
a recovered oil fraction and a water fraction containing dissolved silica,
hardness,
total organic carbon, and other dissolved organic and inorganic contaminants.
A
high temperature electrocoagulation system may be provided for ionizing,
complexing, and/or absorbing the dissolved silica, hardness, total organic
carbon,
and other dissolved organic and inorganic contaminants in the water fraction,
producing a vapor fraction and a solids/froth/water mixture. The system may
also
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include a water separation and solids/froth/sludge dewatering system for
separating
the solids/froth/water mixture into a sludge fraction and a clarified water
fraction; a
polishing system for reducing a total hardness of the clarified water fraction
to less
than 0.2 ppm and producing a regeneration waste water stream and a boiler feed
water stream. A steam generation system may convert the boiler feed water
stream
to steam; an outlet for providing steam from the steam generation process to
the
enhanced oil recovery system.
[0007] In some embodiments, the deoiling system may include a free water
knockout
drum to separate the oil-water emulsion into a free water fraction and an oil-
emulsion fraction; an oil treater for contacting the oil-emulsion fraction
with a
hydrocarbon solvent to reduce a density and viscosity of the hydrocarbons in
the oil-
emulsion fraction and forming an oil fraction and a water-oil suspension
containing
residual oil; a skim/surge tank for coalescing the residual oil in the water-
oil
suspension and producing a coalesced oil fraction and a water effluent; a
dissolved
gas flotation unit for further de-oiling the water effluent, producing an oil
fraction
and a water fraction containing less than 10 ppm oil; and an optional deoiled
/
makeup water storage tank for storing the water fraction prior to feed to the
high
temperature electrocoagulation system.
[0008] The deoiling system may also include a diluent feed system for
providing the
hydrocarbon solvent to the deoiling system. In some embodiments, natural gas
feed
system for providing natural gas to one or more tanks of the deoiling system,
and/or
a heat exchanger for reducing a temperature of the water-oil suspension to
less than
95 C via indirect heat exchange with one or more of air, glycol, or boiler
feed water,
and/or an oil recovery / slop tank for further dewatering of the coalesced oil
fraction.
One or more feed lines may also be provided in the deoiling system for
admixing the
water fraction with one or more of groundwater, brackish water, filtered
makeup
water, or recycled neutralized ion exchange regenerant waste water or for
providing
one or more of groundwater, brackish water, filtered makeup water, or recycled
neutralized ion exchange regenerant waste water to the skim/surge tank.
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[0009] The water-oil suspension may have less than 3000 ppm residual oil.
The
system may also include a chemical treatment feed system for admixing
chemicals
with the water-oil suspension to enhance coalescence of oil droplets.
[0010] The high temperature electrocoagulation system may include
electrocoagulation cells for ionizing, complexing, and/or absorbing the
dissolved
silica, hardness, total organic carbon, and other dissolved organic and
inorganic
contaminants in the water fraction. The high temperature electrocoagulation
system
may further comprise of a vapor inlet for injecting a gas into the
electrocoagulation
cells for promoting flotation and removal of solids/froth generated.
[0011] The system may also include a chemical feed system for mixing pre-
treatment
chemicals with the water fraction prior to processing the water fraction in
the
deoiling system and high temperature electrocoagulation system. In various
embodiments, the water separation and solids/froth/sludge dewatering system
comprises one or more of a vacuum clarifier, a filter press, a sequential
baffle
solids/froth separating / breaking cell or tank, a hydrocyclone, a dissolved
gas
floatation system, a micro-media filter, a settling pond, or a sludge
dewatering filter
press.
[0012] A sludge conditioning chemical addition system may be used in some
embodiments for admixing sludge conditioning chemicals to the solids/froth or
sludge fraction upstream or downstream of one or more of the hydrocyclone,
dissolved gas floatation system, the settling pond, or the sludge dewatering
filter
press. The polishing system may include one or more of a strong acid cation
exchanger or a weak acid cation exchanger, wherein the exchangers are used
alone
or together, and in series or in parallel. The system may also include a
neutralization
regen waste storage tank for receiving the regeneration waste water stream and
an
additive feed system for adjusting the pH of the regeneration waste water
stream. A
flow line may be provided for feeding pH adjusted regeneration waste water
from
the neutralization regen waste storage tank to the deoiling system or for
admixture
with the water fraction upstream of the high temperature electrocoagulation
system.
[0013] The system may also include a steam deaerator for removing
entrained gases
from the boiler feed water stream. Additionally, the steam generation system
further
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comprising one or more of: an ammonia or volatile amine feed system for
admixing
ammonia or a volatile amine with the steam upstream of the enhanced oil
recovery
system; a medium/low pressure steam separator; a disposal well treatment
process;
disposal tanks; an excess utility steam condenser; an oxygen scavenger and
boiler
feed water conditioner additive system; a desuperheater; a flash evaporator; a
crystallizer; or a carbon dioxide scrubber.
[0014] In another aspect, embodiments disclosed herein relate to a process
for
providing steam to an enhanced oil recovery system. The process may include a
step of receiving an oil-water emulsion from an enhanced oil recovery system,
the
emulsion comprising one or more of dissolved solids, entrained gases and/or
light
hydrocarbons, distillate and/or heavier hydrocarbons, and water. The entrained
gases and/or light hydrocarbons may be separated from the oil-water emulsion,
producing a vapor stream and an oil-water stream. The oil-water stream may be
separated into a recovered oil fraction and a water fraction containing
dissolved
silica, hardness, total organic carbon, and other dissolved organic and
inorganic
contaminants. The water fraction may then be processed in a high temperature
electrocoagulation system for ionizing, complexing, and/or absorbing the
dissolved
silica, hardness, total organic carbon, and other dissolved organic and
inorganic
contaminants in the water fraction, producing a vapor fraction and a
solids/froth/water mixture. The solids/froth/water mixture may be separated
into a
sludge fraction and a clarified water fraction. A total hardness of the
clarified water
fraction may be reduced to less than 0.2 ppm, producing a regeneration waste
water
stream and a boiler feed water stream. A steam generation system may then
convert
the boiler feed water stream to steam, providing steam from the steam
generation
process to the enhanced oil recovery system.
DETAILED DESCRIPTION
[0015] Embodiments disclosed herein relate generally to systems and
processes for
water treatment, steam generation and waste treatment. In some embodiments,
central processing facilities disclosed herein may be used in association with
enhanced oil recovery systems, such as cyclic steam stimulation (CSS), steam
assisted gravity drainage (SAGD) or other heavy oil recovery systems, to deoil
the
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water, treat the water, generate steam, and treat generated wastes. In other
embodiments, central processing facilities disclosed herein, or variants
thereof, may
be used in association with other processes that may benefit from such water
treatment or enhancement processes, such as mining operations.
[0016] The "Front To Back" (FTB) Central Processing Facility (CPF) systems
disclosed herein may incorporate six major water treatment, steam generation
and
blowdown waste treatment steps for Steam Assisted Gravity Drainage (SAGD),
Cyclic Steam Stimulation (CSS), or Steam Flood enhanced oil recovery
operations.
[0017] The major steps that may be included in embodiments herein are:
High
Quality De-oiling; high temperature Electrocoagulation (EC); EC Sludge/ Solids
Separation, Dewatering, and Filtration; Low Hardness (Polishing) and
Deaeration;
Once-Through Steam Generators (OTSGs) or Force Circulation Steam Generators
(FCSGs) or Heat Recovery Steam Generators (HRSGs) for High and/or Low
Pressure Steam Production; and Blowdown Waste Treatment.
[0018] The heart of the water treatment process incorporates the use of a
high
temperature (HT) EC process for efficient and cost effective removal of
hardness,
silica, total organic carbon and suspended solids. The HT EC process has yet
to be
utilized commercially for primary treatment of produced or mixed produced plus
fresh and/or brackish makeup water in steam enhanced operations in the heavy
oil
industry. Integrating EC as a primary treatment process results in a reduction
in the
composition complexity of boiler feed water (BFW) and blowdown wastewater
produced by the steam generating processes.
[0019] The reduced BFVV composition complexity enables steam generators,
such as
OTSGs, installed at thermal heavy oil facilities to produce a steam quality in
excess
of 90% while significantly reducing the risk of organic or mineral salt
fouling,
overheating and failure of tubes in the steam generator convection or radiant
sections. Similarly, due to the reduced blowdown wastewater composition
complexity, the risk of fouling or plugging of disposal systems is
significantly
reduced whether the FTB CPF design includes the application of evaporator
processes installed downstream of the steam generating processes or not. The
reduced wastewater composition complexity enables the efficiency and service
CA 2962834 2017-03-30
factor of optional evaporation processes and subsequent waste disposal systems
described herein to be maximized.
[0020] Key changes to current CPF designs used for the heavy oil industry
through
application of one of the FTB CPF designs according to embodiments herein may
include one or more of: Exclusion of Oil Removal Filters; Exclusion of Hot or
Warm Lime Softeners; Exclusion of Front End Mechanical Vapor Compression;
Exclusion of Primary Ion Exchangers; Exclusion of Disposal Wells for handling
Ion
Exchange Regeneration Wastes; and Reduction of Waste Solids quantity, toxicity
and/or handling complexity generated for landfill compared to lime softening
processes or Zero Liquid Discharge (ZLD) processes.
[0021] The improved BFW quality generated by the FTB process enables once-
through steam generators ("OTSG") to generate a steam quality of >90%, thereby
reducing high pressure and subsequent low pressure separator blowdown streams
by
>50%, relative to traditional targets currently used. The much lower blowdown
production allows the producer to meet or exceed the current environmental
regulatory guidelines, such as those set forth in the Alberta Energy Resources
guidelines, without further blowdown waste treatment. Depending on the total
dissolved solids (TDS) concentration of the produced water from the field and
availability of disposal wells, salt cavern or other disposal services, the
FTB CPF
design can eliminate the need to utilize evaporation to further reduce
blowdown
waste to disposal.
[0022] Where the TDS of the produced water or combined produced-makeup
waters
result in generating BFW that is above the allowable OTSG operating
specifications
or where waste water disposal options are limited or too costly, the FTB CPF
design
options available can reduce BFW TDS or reduce waste to disposal to achieve
near
ZLD or actual ZLD capability. These reductions may be achieved through the use
of
either a slip stream evaporator or the use of steam generation blowdown
evaporation
and crystallization without the challenges of handling high hardness or high
silica
and high molecular weight organics in the evaporation or crystallization
processes.
[0023] In addition to adopting the entire FTB-CPF design for new plants,
embodiments herein may incorporate EC with other water treatment processes in
the
overall FTB-CPF design to provide add-on debottlenecking solutions to increase
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steam quality or increase the quantity of steam to field for thermal heavy oil
facilities. The facilities where the add-on debottlenecking FTB designs can be
used
include but are not limited to: Smaller Ion Exchange only - OTSG operations,
Larger Lime Softening-OTSG operations, and Evaporator - Drum Boiler
operations.
[0024] The FTB-CPF designs according to embodiments herein, and useful for
full
scale commercial CSS, Steam Flood, and SAGD thermal heavy oil operations are
shown in Figures 1-14, where Figures 1-6 focus on FTB-CPF cyclic steam
stimulation configurations, and Figures 7-14 focus on FTB-CPF steam assisted
gravity drainage configurations, each of which are described further below.
[0025] HIGH QUALITY DEOILING
[0026] Oil/Water/Gas emulsion streams entering the Central Processing
Facility
undergo field gas separation followed by primary oil-from-water separation
that
occurs through the use equipment such as a Free Water Knockout (FWKO) and an
Oil Treater (OT) that may, in some embodiments, utilize the addition of a
hydrocarbon solvent or "diluent" to lower the density and viscosity of the oil
and
enhance oil separation from the water. The produced water recovered from the
FWKO and OT may be cooled to less than 95 C through heat exchange with OTSG
BFW and (if needed) an aerial or glycol cooler. The produced water from the
FWKO and OT is transferred to a skim/surge tank (ST), and may contain an
average
of 2000 ppm of residual oil, in some embodiments, less than 3000 ppm or less
than
3500 ppm in other embodiments, with excursions that may exceed 5000 ppm for
short periods.
[0027] The produced water-oil suspension in the feed to the ST is
chemically treated
to enhance coalescence of the oil droplets to effect more rapid gravity
separation of
the oil that rises to the surface in the tank. The ST may be designed to
reduce the oil
in water concentration in the effluent to 10% of the inlet concentration. The
oil
separated in the ST is skimmed off and returned to either the FWKO or an oil
recovery/slop tank for additional treatment and dewatering. Embodiments of the
current processes allow the elimination of other steps that would normally be
found
in existing processes, including Hot/Warm lime softening and/or front end MVC
vapor recovery.
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[0028] The ST effluent is further de-oiled with a dissolved gas floatation
unit (DGF).
The dissolved gas floatation unit may be designed to reduce the oil in water
to less
than 10 ppm, for example. Oil that is separated from the water and skimmed off
from the DGF unit is returned to the skim tank or transferred to the
recovery/slop oil
tank.
[0029] The deoiled produced water from the DGF unit may be transferred to
an
optional deoiled / makeup water storage tank, where the deoiled product may be
thoroughly mixed with filtered makeup water from groundwater or surface water
sources (with or without pH adjustment) and recycled neutralized weak acid
cation
exchange regenerant waste water prior to being transferred to the high
temperature
electrocoagulation process.
[0030] ELECTROCOAGULATION
[0031] The benefits of high temperature electrocoagulation (HT EC) are the
elimination of the Hot/Warm lime softening and/or eliminating the need for
using
front end evaporators to produce a higher quality BFW to enable the OTSGs to
produce a >90% steam quality that will lower the volume and improve the
quality of
the blowdown (i.e. less silica and organics), enabling the blowdown to be more
easily treated and disposed of. Similarly the FTB processes herein allow the
elimination of a Front End MVC Vapor Recovery process to produce BFW for
steam generation in drum boilers or forced circulation steam generators, both
of
which are not the most cost effective water treatment to steam generation
processes.
As used herein, high temperature electrocoagulation refers to
electrocoagulation
processes operated at, for example, temperatures greater than 60 C.
[0032] The blended water from the deoiled/makeup water storage tank is
pumped and
evenly distributed to the required correctly sized number of operating
electrocoagulation ("EC") cells. EC cells are described, for example, in
W099/43617. The high temperature EC system may be designed to include one
spare cell to enable servicing of an operating cell intermittently as required
while
maintaining treatment throughput capacity. The EC cells, depending on required
capacity, may be sized to hold up to 217 plates, such as iron or aluminum
electrode
plates, for example. DC power is supplied to the cells to deliver up to 7
kw/m3 of
throughput with iron consumption by the process typically between 0.02 to 0.03
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kg/m3 of treated water. The power supply polarity across the plates may be
reversed
periodically to help prevent deposits from building up on the plates.
Additionally, in
some embodiments, the pH of the feed to the HT EC system may be modified to
improve or optimize EC contaminant removal efficiency.
[0033] The iron that dissolves during the EC process is simultaneously
converted to a
charged oxidized particle while ionizing/complexing/absorbing dissolved
silica,
hardness, total organic carbon and many other dissolved organic and inorganic
contaminants, including multivalent contaminants. This sequence promotes
coagulation of the free suspended oil and solids that all combine and make up
the
composition of the entrained suspended solids/froth. The solids/froth/water
mixture
flows out of the EC cell into a collection trough that feeds the downstream
solids/froth/solids water breaking and separation unit. The EC cell and the
trough are
fitted with a vapor containment cover to direct any gases or vapors generated
to a
dedicated knockout drum and discharge vent or recovered for fuel gas or
disposal
using a Vapor Recovery Unit (VRU). The EC unit design includes the option to
inject air or inert gas into the bottom of the cell to promote floatation and
removal of
the solids/froth generated. Fugitive toxic gas emissions are not expected to
exceed
regulatory limits but may be recovered through the use of a VRU.
[0034] The electrode plates and EC cells are cleaned, "pickled,"
sequentially and
routinely to maintain electrocoagulation energy efficiency using a dilute HC1
or
H2SO4 acid clean-in-place (CIP) solution stored in a separate single tank
dedicated
to service all EC cells. The CIP solution is used over and over until the acid
strength
is depleted at which time the exhausted solution is pH neutralized and
directed back,
at a steady controlled rate, into the feed distribution line to the EC cells
for treatment
where the contaminants in the solution are removed as solids/froth.
[0035] SOLIDS SEPARATION, DEWATERING and FILTRATION
[0036] The solids/froth/water mixture generated by the EC process flows
into a
solids-froth-water separation process. Three process options may be used to
remove
the froth entrained gas and consolidate the entrained solids for dewatering.
[0037] Option 1 ¨Solids/Froth Breaking Cell and HydroCyclone
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[0038] The first option is to allow the EC froth-water mixture into to a
three stage
enclosed sequential cascading solids/froth breaking (defoaming) cell. The
solids/froth breaker uses strategically designed spreaders and water sprays to
break
the foam and entrain the solids. The solids entrained water passes through
hydrocyclones designed to maximize the removal of fine entrained solids, such
as
particles, and reduce the clarified solids concentration in the effluent to
less than 30
mg/L. The hydrocyclone system may include provisions to include coagulation or
flocculation upstream or downstream to further maximize solids removal and
subsequent filtration or dewatering efficiency. The separated solids collected
in the
bowl of the hydrocyclone unit are discharged, as required, to be sent to a
surge tank
and filter press for final dewatering and subsequent landfill, or may be
alternatively
sent to a settling pond or centrifuge for disposal. Off spec water from the
hydrocyclones will be treated with chemical and may be recycled back through
the
EC system or defoaming unit via the filter dirty backwash storage tank for re-
processing or sent through a secondary off-spec polishing hydrocyclone unit.
[0039] Option 2 ¨ Vacuum Clarifier & Filter Press
[0040] The second option passes the solids/froth/treated water mixture
down through
a vacuum clarifier to collapse the solids/froth and allow solids to gravity
settle and
concentrate in a clarifier tank below. The settled solids are removed via a
bottom
rotating rake in the tank to be removed and pumped to a filter press or
alternatively
to a pond or centrifuge for dewatering.
[0041] Option 3 ¨Froth Transfer and Gas Floatation
[0042] The third option is to transfer the froth laden treated EC mixture
to a DGF
unit. The use of air, nitrogen or sweet natural gas may be selected as the
floatation
gas for the DGF. The solids/froth in the feed to the DGF are separated from
the
produced water by gas floatation and skimmed off the top. The skimmed solids
are
transferred to a solids slurry-mix tank, which may or may not undergo chemical
treatment, to coagulate the solids prior to dewatering by either a filter
press or
centrifuge or alternatively sent to a settling pond.
[0043] The clarified separated water from any of the above water solids
separation
processes is filtered using micro-media filters or alternatively
ultrafiltration
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membranes to remove trace solids from the clarified water. The filters are
designed
to produce an effluent having a turbidity value of less than 2 and a solids
content of
less than 1 ppm. When solids loading on the micro media filters create a
pressure
drop that reduces the throughput capacity of the filters, the filter media is
air or gas
scoured and then backwashed. Should an ultrafiltration system be utilized the
membranes are constantly discharging a concentrated slurry to the dirty
backwash
tank and undergo a high pressure back pulse intermittently to dislodge
entrapped
solids within the membrane lattice. Filtrate from the media filters supplies
clean
backwashing (BW) water to the clean BW water storage tank. The dirty backwash
or
slurry stream from the filtration system backwashing sequence is sent to a
dirty
backwash tank then recycled back to the inlet of the solids/froth defoaming
cell or
hydrocyclone unit. Intermittent chemical cleaning combined with air scour
cleaning
of the micro-media filter media is optional and used as required to maintain
media
quality and filter performance.
[0044] RESIDUAL HARDNESS REMOVAL AND DEAERATING
[0045] The effluent from the EC process and filtration system may contain
hardness
that requires removal using Weak Acid Cation (WAC) polishers to an acceptable
BFW concentration of less than 0.2 ppm. The WAC units are operated in the
Sodium (Nat) form and are regenerated in-situ with dilute HC1 (acid) to remove
the
exchanged hardness then converted to the Na + form with dilute NaOH (caustic).
Boiler Feed Water is used to dilute the concentrated chemicals delivered to
the plant
to prepare the chemical regenerants. When process conditions and produced
and/or
makeup water total hardness (TH) levels are excessive thereby significantly
increasing the EC effluent TH, thereby risking hardness leakage into the BFW
stream, embodiments herein contemplate the use of a dual primary ¨ polishing
WAC
ion exchange configuration to be included in the FTB-CPF design.
[0046] A unique feature of the FTB-CPF design is the recycling and
treatment of the
regeneration waste water. The regeneration waste water generated may be pH
adjusted to neutrality in a neutralization tank with additional acid or
caustic then
recycled in a slow controlled manner to the inlet of the EC cells while in
operation
or mixed with the incoming produced water in the skim or optional deoiled /
make-
up water storage tank. When the regeneration waste water hardness is processed
by
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the EC unit the majority of the hardness contaminants are removed as solids to
a
level required for ion exchange. This recycle treatment feature eliminates the
need
for a dedicated waste disposal well for the regeneration waste water or the
use of
costly chemicals to precipitate the waste dissolved hardness by lime
softening. The
sodium and chloride ions present in the regeneration waste water stream are
monovalent ions and are not removed by the EC process and significantly impact
the
TDS of the regenerant waste water. High TDS of the regenerant waste water will
impact the total TDS and chloride concentration of the BFW somewhat depending
upon regenerant waste water volume and rate of recycle. For thermal heavy oil
produced waters the TDS and chloride concentrations are typically low enough
to
enable recycle of the regeneration waste water while maintaining a BFW
chloride
concentration below the maximum target concentration of 3500 mg/L for OTSGs
fitted with conventional tubing material and producing at least 90% steam
quality.
[0047] The softened BFW may be deaerated using a steam deaerator before
being
stored in a BFW storage tank prior to steam generation. Steam to the deaerator
may
be supplied from the medium and/or low pressure steam separators located in
the
steam plant or via a low pressure letdown station should insufficient low
pressure
steam be available for the deaerator. The deaerated BFW out of the BFW storage
tank may be treated with an oxygen scavenger to remove trace oxygen to less
than
0.007 ppm and if necessary caustic to adjust the pH to 9.0 to meet boiler
feedwater
guidelines, such as those specified by the American Boiler Manufacturers
Association (ABMA) or the American Society of Mechanical Engineers (ASME).
[0048] STEAM GENERATION
[0049] The OTSG steam generators, which may or may not be fitted with
rifle tubes
in up to 50% of the latter part of the radiant section, may be used to produce
90% or
greater steam quality.
[0050] For CSS or Steam Flood facilities, all of the 90% quality steam
that the OTSG
produces may be sent to the field for injection. At CSS or Steam Flood
facilities the
utility steam needed to operate the FTB deaerator is supplied via a high
pressure
steam letdown station on the outlet of the OTSGs or alternatively a utility
boiler
package is provided.
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[0051] For SAGD facilities, the steam phase is separated from the liquid
phase by a
high pressure separator (HPS) to deliver 100% quality steam to the field. At
SAGD
facilities, a volatile-filming amine may be injected into the 100% steam to
field
distribution line as the traditional method to control the potential for
carbonic acid
corrosion in the line. An alternative option may be used for the FTB CPF
designs
according to embodiments herein, where liquefied ammonia may be used to
provide
similar corrosion protection.
[0052] For SAGD facilities where the HPS produces blowdown (BD) the HP BD
pressure is let down in a medium pressure (MP) and/or a low pressure (LP)
steam
separator with an optional de-super heater installed off the HPS unit to
ensure
sufficient utility steam is available for subsequent blowdown treatment to
maximize
water reuse and minimize waste disposal quantities. The MP plus LP steam
separators together typically can convert up to 40% of the water to MP and LP
steam
that is used to operate the BFW steam deaerator and provide some or all of the
steam
needed to operate an optional "back-end" multiple effect evaporator or
optional
crystallizer for maximizing water reuse and minimizing blowdown waste for
disposal. Where insufficient MP or LP steam is available for operating back-
end
blowdown waste reduction evaporators and optional crystallizers, additional
steam
may be supplied via a de-super heater.
[0053] BOILER PRIMARY AND SECONDARY BLOWDOWN TREATMENT
[0054] The blowdown remaining from the MP or LP steam separator can be
cooled
via cross exchange with BFW, and / or an aerial or glycol cooler, and sent to
a
disposal well. The volume of blowdown may meet the regulatory guidelines for
waste disposal and water reuse. The FTB-CPF options available to maximize
water
reuse and minimize disposal include additional treatment utilizing a multiple
effect
evaporator system with optional stack gas scrubber and/or optional
crystallizer
system to: meet regulatory guidelines; achieve near ZLD capability;
Participate in a
Green House Gas emission reduction initiatives to receive carbon credits or
reduce
carbon taxes; and/or achieve ZLD capability.
[0055] Figures 2-4 and 6-10 are various FTB-CPF Block Flow Diagrams that
illustrate the TDS reduction evaporator and blowdown evaporator treatment
options
for CSS and SAGD facilities, and are described further below. The FTB-CPF for
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steam flood facilities is essentially the same as the CSS case except for
minor
differences in the oil treating unit, but the water treatment and steam
generation
units are identical.
[0056] The FTB-CPF design provides for recycle of a portion of the
blowdown
stream back to the HT EC unit inlet, should the TDS of the BFW be less than
5770
ppm for a 90% steam quality OTSG operations having radiant tubes rated for
handling up to 35,000 mg/L of chlorides in the blowdown water phase. For
higher
TDS BFW, the OTSG radiant section tube material of construction for some or
all of
the tubes may be changed to handle higher chloride concentrations, which may
not
be economically feasible, thereby preventing further recovery of blowdown
fluids.
[0057] The above-described processes according to embodiments herein are
illustrated in Figures 1-10, described below.
[0058] The block flow diagram of Figure 1 provides an overview of a front-
to-back
central processing facility for a CSS enhanced oil recovery system according
to
embodiments herein. Figure 1, similar to other figures herein, is a block flow
diagram, illustrating primary steps in the CSS FTB-CPF designs according to
embodiments herein.
[0059] The front-to-back central processing facility for a CSS enhanced
oil recovery
system as illustrated in Figure 1 may include six primary stages, including
primary
gas-oil-water separation stage 10, a high quality de-oiling stage 20, high
temperature
electrocoagulation stage 30, waste separation and froth/sludge dewatering
stage 40,
low hardness removal and boiler feed water storage stage 50, and steam
generation
stage 60.
[0060] A produced emulsion 12, such as an oil-water emulsion from an
enhanced oil
recovery system, is fed to an inlet of the gas-oil-water separation stage 10.
The
produced oil-water emulsion may be provided directly or indirectly from an
enhanced oil recovery system, and may include one or more of dissolved solids,
entrained gases and/or light hydrocarbons, distillate and/or heavier
hydrocarbons,
and/or water. In primary gas-oil-water separation stage 10, the emulsion is
treated so
as to separate the entrained gases and light hydrocarbons from the oil and
water in
the emulsion. The gases evolved may be fed via flow line 14 to a vapor
recovery
14
CA 2962834 2017-03-30
unit (not shown) for further processing. The remaining oil-water emulsion may
then
be fed via flow line 16 to de-oiling stage 20.
[0061] Deoiling system 20 may separate the oil-water emulsion in stream 16
into a
recovered oil fraction 22 and a water fraction 24. Water fraction 24 may
contain,
among other components, dissolved silica, hardness, total organic carbon, and
other
dissolved organic and inorganic contaminants. To facilitate the separations, a
hydrocarbon solvent 25 may be used to reduce a density and viscosity of the
hydrocarbons in the oil-emulsion fraction and forming an oil fraction and a
water-oil
suspension containing residual oil.
[0062] To maintain an inert atmosphere in various tanks and other unit
operations in
the de-oiling system, a blanket gas that is typically natural gas and could be
an inert
gas, such as nitrogen, may be provided via flow line 26. The vapors recovered
from
the tank and unit operation vents may be recovered via one or more flow lines
23
and fed to a vapor recovery unit, such as a common vapor recovery unit with
the
primary gas-oil-water separations, for recovery or further processing of the
vapor
streams, including any water, vaporized solvent, and light hydrocarbons
therein.
[0063] Other feed streams to the de-oiling system may include a water feed
27, which
may be used to provide fresh ground, brackish, or make-up water to the system.
Lastly, a neutralized regen waste recycle stream 28 may be provided from low
hardness removal and boiler feed water storage stage 50 for further processing
through the FTB-CPF.
[0064] The water fraction 24 may then be fed to high temperature
electrocoagulation
system 30. The high temperature electrocoagulation system is configured for
ionizing, complexing, and/or absorbing the dissolved silica, hardness, total
organic
carbon, and other dissolved organic and inorganic contaminants in the water
fraction, producing a vapor fraction 32 and a solids/froth/water mixture 34.
Chemicals may be used to pre-treat the feed to the high temperature
electrocoagulation unit, and may be supplied via flow line 36. A recycle
stream 38,
such as a filtrate recycle from waste separation and solids/froth/sludge
dewatering
stage 40 may also be provided to the high temperature electrocoagulation
system.
[0065] Water separation and solids/froth/sludge dewatering system 40 may
separate
the solids/froth/water mixture 34 into a sludge fraction 42, which may include
CA 2962834 2017-03-30
filtered solids, and a clarified water fraction 44. A vapor stream 46 may also
be
recovered from water separation and solids/froth/sludge dewatering stage 40,
and
processed in the above-noted vapor recovery unit. Sludge conditional
chemicals, if
used, may be fed to water separation and solids/froth/sludge dewatering system
40
via flow line 48.
[0066] The clarified water fraction 44 may then be fed to low hardness
removal and
boiler feed water storage stage 50. The "polishing" system may reduce a total
hardness of the clarified water fraction to less than 0.2 ppm, for example,
producing
a regeneration waste water stream 28 and a boiler feed water stream 52. Ion
exchange regen chemicals may be fed to system 50 via flow line 54, and vent
gases
recovered via flow line 56 may be processed in the vapor recovery unit, as
noted
above. Steam used in the polished water deaerator for producing and pre-
heating
boiler feed water for storage stage 50 may be supplied from the steam
generation
stage 60 via flow line 58.
[0067] Steam generation stage 60 may be used to convert the water in
boiler feed
water stream 52 to steam, such as by using once through steam generators, as
noted
above. Steam generated in steam generation system 60 may be provided to the
enhanced oil recovery system (not shown) via flow line 62, to the polished
water
deaerator for producing and pre-heating boiler feed water for storage stage 50
via
flow line 58, and to other uses via one or more steam lines 64. Other outputs
from
steam generation stage 60 may include OTSG stack gas 66, solids / landfill
waste
stream 67, and blowdown water 68 to a disposal well or treatment process (not
shown). As needed, boiler feed water conditioner 70 and oxygen scavenger 72
may
be introduced to the steam generation system 60 as well.
[0068] Various steps within each of the noted system blocks illustrated in
Figure 1 are
described above, and below in Figures 2-6, and as such are not described in
detail
with respect to Figure 1. Figure 1 simply provides a general overview of the
various
systems used in the FTB-CPF according to embodiments herein that may be used
with a CSS enhanced oil recovery system.
[0069] Referring now to Figure 2, a block process flow diagram of a front-
to-back
central processing facility for a CSS enhanced oil recovery system according
to
16
CA 2962834 2017-03-30
embodiments herein is illustrated, illustrating embodiments of steps 10 and 20
of
Figure 1 in greater detail, where like numerals represent like parts.
[0070] A produced emulsion 12, such as an oil-water emulsion from a CSS
enhanced
oil recovery system, is fed to an inlet of the gas-oil-water separation stage
10. The
produced oil-water emulsion may be provided directly or indirectly from a CSS
enhanced oil recovery system, and may include one or more of dissolved solids,
entrained gases and/or light hydrocarbons, distillate and/or heavier
hydrocarbons,
and/or water. In primary gas-oil-water separation stage 10, the emulsion may
be
treated initially in a Free Water Knockout (FWKO) drum 210 to separate the
entrained gases and light hydrocarbons from the oil and water in the emulsion.
The
gases evolved may be fed via flow line 14 to a vapor recovery unit (not shown)
for
further processing. The remaining oil-water emulsion may then be fed via flow
line
16 to de-oiling stage 20.
[0071] Deoiling system 20 may separate the oil-water emulsion in stream 16
into a
recovered oil fraction 22 and a water fraction 24. Water fraction 24 may
contain,
among other components, dissolved silica, hardness, total organic carbon, and
other
dissolved organic and inorganic contaminants. Oil-water emulsion 16 may be fed
to
an Oil Treater (OT) 215 for recovery of oil from water. To facilitate the
separations
in OT 215, a hydrocarbon solvent 25 may be used to reduce a density and
viscosity
of the hydrocarbons in the oil-emulsion fraction and forming an oil fraction
22 and a
water-oil suspension (produced water) 217 containing residual oil.
[0072] The produced water 217 recovered from the FWKO 210 and OT 215 may
be
cooled to less than 95 C through heat exchange with OTSG BFW and (if needed)
an
aerial or glycol cooler (one or more exchangers 219). The produced water 217
from
OT 215 is transferred to a skim/surge tank (ST) 220, and may contain an
average of
2000 ppm of residual oil, in some embodiments, less than 3000 ppm or less than
3500 ppm in other embodiments, with excursions that may exceed 5000 ppm for
short periods.
[0073] The produced water-oil suspension 217 in the feed to ST 220 may be
chemically treated to enhance coalescence of the oil droplets to effect more
rapid
gravity separation of the oil that rises to the surface in the tank. The ST
220 may be
designed to reduce the oil in water concentration in the effluent to 10% of
the inlet
17
CA 2962834 2017-03-30
concentration. The oil separated in ST 220 is skimmed off and returned via
flow line
222 to one of OT 215, FWKO 210, or an oil recovery/slop tank (not illustrated)
for
additional treatment and dewatering.
[0074] ST 220 effluent 224 may be further de-oiled with a dissolved gas
floatation
unit (DGF) 225. The DGF unit 225 may be designed to reduce the oil in water to
less than 10 ppm, for example. Oil that is separated from the water and
skimmed off
from the DGF unit may be returned via flow line 227 to the skim tank 220 or
transferred to a recovery/slop oil tank (not shown).
[0075] The deoiled produced water 229 from the DGF unit 225 may be
transferred to
an optional deoiled / makeup water storage tank 230, where the deoiled product
may
be thoroughly mixed with filtered makeup water 27 from groundwater or surface
water sources (with or without pH adjustment) and recycled neutralized weak
acid
cation exchange regenerant waste water 28 prior to being transferred to the
high
temperature electrocoagulation process (Figure 3) via flow line 24.
[0076] To maintain a non oxidizing atmosphere in various tanks and other
unit
operations in the de-oiling system, a blanket gas that is typically natural
gas but
could be an inert gas, such as nitrogen, may be provided via flow line 26. The
vapors recovered from the tank and unit operation vents may be recovered via
one or
more flow lines 23 and fed to a vapor recovery unit, such as a common vapor
recovery unit with the primary gas-oil-water separations vent 14, for recovery
or
further processing of the vapor streams 14, 26, including any water, vaporized
solvent, and light hydrocarbons therein.
[0077] Referring now to Figure 3, a block process flow diagram of a front-
to-back
central processing facility for a CSS enhanced oil recovery system according
to
embodiments herein is illustrated, illustrating embodiments of steps 30 and 40
of
Figure 1 in greater detail, where like numerals represent like parts.
[0078] The water fraction 24 may then be fed to high temperature
electrocoagulation
system 30. The high temperature electrocoagulation system is configured for
ionizing, complexing, and/or absorbing the dissolved silica, hardness, total
organic
carbon, and other dissolved organic and inorganic contaminants in the water
fraction, producing a vapor fraction 32 and a solids/froth/water mixture 34.
The
blended water 24 from the deoiled/makeup water storage tank is pumped and
evenly
18
CA 2962834 2017-03-30
distributed to the required correctly sized number of operating
electrocoagulation
("EC") cells in high temperature EC system 30. As noted above, the EC cells
may
hold iron or aluminum plates, for example. DC power is supplied to the cells
to
deliver up to 7 kw/m3 of throughput with electrode plate consumption by the
process
typically between 0.02 to 0.03 kg/m3 of treated water.
[0079] Chemicals used to pre-treat the feed to the high temperature
electrocoagulation
unit may be supplied via flow line 36. A recycle stream 38, such as a filtrate
recycle
from clean boiler water storage tank 320 in waste separation and froth/sludge
dewatering stage 40 may also be provided to the high temperature
electrocoagulation
system.
[0080] The power supply polarity across the plates may be reversed
periodically to
help prevent deposits from building up on the plates. Additionally, in some
embodiments, the pH of the feed to the HT EC system may be modified to improve
or optimize EC contaminant removal efficiency. The iron or aluminum electrodes
that dissolve during the EC process is simultaneously converted to a charged
oxidized particle while ionizing/complexing/absorbing dissolved silica,
hardness,
total organic carbon and many other dissolved organic and inorganic
contaminants,
including multivalent contaminants. This sequence promotes coagulation of the
free
suspended oil and solids that all combine and make up the composition of the
entrained suspended froth 34. The solids/froth/water mixture 34 flows out of
the EC
cell into a collection trough (not shown) that feeds the downstream
solids/froth
water separation unit 325. The HT EC cell and the trough may be fitted with a
vapor
containment cover to direct any gases or vapors generated via flow line 32 to
a
dedicated knockout drum and discharge vent or recovered for fuel gas or
disposal
using a Vapor Recovery Unit (VRU) (not shown), which may be the same or
different VRU than that used with respect to stages 10 and 20. The HT EC unit
30
design may include the option to inject air or inert gas 323 into the bottom
of the cell
to promote floatation and removal of the froth solids generated. Fugitive
toxic gas
emissions are not expected to exceed regulatory limits but may be recovered
through
the use of the VRU.
[0081] The electrode plates and EC cells are cleaned, "pickled,"
sequentially and
routinely to maintain electrocoagulation energy efficiency using a dilute HC1
or
19
CA 2962834 2017-03-30
H2SO4 acid clean-in-place (CIP) solution stored in a separate single tank 329
dedicated to service all EC cells. The C1P solution is used over and over
until the
acid strength is depleted at which time the exhausted solution is pH
neutralized and
directed back, at a steady controlled rate, into the feed distribution line to
the EC
cells for treatment, where the contaminants in the solution are removed as
solids in
the froth 34.
[0082] Water separation and froth/sludge dewatering system 40 may separate
the
solids/froth/water mixture 34 into a sludge fraction 42, which may include
filtered
solids, and a clarified water fraction 44. A vapor stream 46 may also be
recovered
from water separation and froth/sludge dewatering stage 40, and processed in
the
above-noted vapor recovery unit. Sludge conditional chemicals, if used, may be
fed
to water separation and froth/sludge dewatering system 40 via flow line 48.
[0083] As illustrated in Figure 3, the HT EC effluent, froth-water mixture
34, nay be
fed into to a three stage enclosed sequential cascading froth breaking
(defoaming)
cell 325. The froth breaker 325 uses strategically designed spreaders and
water
sprays to break the foam and entrain the solids, producing a solids entrained
water
effluent 331.
[0084] The solids entrained water 331 passes through hydrocyclones 330,
which may
be designed to maximize the removal of fine entrained solids as small as 10
micron
in size, and reduce the clarified solids concentration in the resulting
effluent 337 to
less than 30 mg/L. The hydrocyclone system 330 may include provisions to
include
coagulation of flocculation upstream or downstream to further maximize solids
removal and subsequent filtration efficiency. The separated solids collected
in the
bowl of the hydrocyclone unit are discharged via flow line 339, as required,
and sent
to a surge tank and filter press 340 for final dewatering and subsequent
landfill of
solids 42. Off spec water 336 from the hydrocyclones may be treated with
chemical
and may be recycled back through the EC system (as shown) or defoaming unit
via
the filter dirty backwash storage tank for re-processing or sent through a
secondary
off-spec polishing hydrocyclone unit (not shown).
[0085] The clarified separated water 337 from hydrocyclone 330 is then
filtered using
micro-media filters 345 or alternatively ultrafiltration membranes to remove
trace
solids from the clarified water. The filters 345 may be designed to produce an
CA 2962834 2017-03-30
effluent having a turbidity value of less than 2 and a solids content of less
than 1
ppm. When solids loading on the micro media filters 345 create a pressure drop
that
reduces the throughput capacity of the filters, the filter media is air or gas
scoured
and then backwashed. Should an ultrafiltration system be utilized the
membranes are
constantly discharging a concentrated slurry to the dirty backwash tank and
undergo
a high pressure back pulse intermittently to dislodge entrapped solids within
the
membrane lattice. Filtrate from the media filters supplies clean backwashing
(BW)
water to the clean BW water storage tank. The dirty backwash or slurry stream
from
the filtration system backwashing sequence is sent to a dirty backwash tank
then
recycled back to the inlet of the solids/froth defoaming cell. Intermittent
chemical
cleaning via clean-in-place system 346 combined with air scour cleaning of the
micro-media filter media is optional and may be used as required to maintain
media
quality and filter performance.
[0086] The clarified water fraction 44 may then be fed to the clean
backwash water
storage tank, the low hardness removal and steam deaerator stage 50 (Figure 4)
and
boiler feed water storage tank 320. One or more water storage tanks 320 may be
used to provide a water stream 38 to the HT EC unit 30, as well as feed 44B to
stage
50, as a supply of water 348 for backwash of the filtration system 345, and as
a
supply 354 of water to filter press 340, as needed. For example, a first tank
920 may
be used to supply dilution water for the chemicals required for regeneration
of the
ion exchangers, and clean service water may be provided from a clean backwash
water storage tank 920 to provide service water to the HC EC unit (rinse after
CIP
treatment), Defoaming Cell, Filter Press and backwashing of the media filters.
Water recovered from the dewatering filter press 340 may be returned via flow
line
352 to either HT EC unit 30 or filtration unit 345 for further processing.
[0087] Referring now to Figure 4, a block process flow diagram of a front-
to-back
central processing facility for a CSS enhanced oil recovery system according
to
embodiments herein is illustrated, illustrating embodiments of steps 50 and 60
of
Figure 1 in greater detail, where like numerals represent like parts.
[0088] The clarified water fractions 44, 44B may then be fed to the clean
backwash
water storage tank and low hardness removal stage 50, which may include an ion
exchange system 410 and a de-aerator 415 in some embodiments. The "polishing"
21
CA 2962834 2017-03-30
system 50 may reduce a total hardness of the clarified water fraction to less
than 0.2
ppm, for example, producing a regeneration waste water stream 28 and a boiler
feed
water stream 52.
[0089] The effluent 44, 44B from the EC process and filtration system may
contain
hardness that requires removal using Weak Acid Cation (WAC) polishers to an
acceptable BFVV concentration of less than 0.2 ppm. The WAC units 410 are
operated in the Sodium (Nat) form and are regenerated in-situ with dilute HC1
(acid)
to remove the exchanged hardness then converted to the Nat form with dilute
NaOH
(caustic). Ion exchange regen chemicals may be fed to system 50 via flow line
54,
and Boiler Feed Water 44B may be used to dilute the concentrated chemicals
delivered to the plant to prepare the chemical regenerants.
[0090] A unique feature of the FTB-CPF design is the recycling and
treatment of the
regeneration waste water. The regeneration waste water 417 generated in the
ion
exchange system 410 may be pH adjusted to neutrality in a neutralization tank
420
with additional acid or caustic then recycled in a slow controlled manner via
flow
line 28 to the inlet of the HT EC cells 30 while in operation or mixed with
the
incoming produced water 217 in the skim tank 220 or optional deoiled / make-up
water storage tank 230 (each in Figure 2). When the regeneration waste water
hardness is processed by the EC unit 30, the majority of the hardness
contaminants
are removed as solids to a level required for ion exchange. This recycle
treatment
feature eliminates the need for a dedicated waste disposal well for the
regeneration
waste water or the use of costly chemicals to precipitate the waste dissolved
hardness by lime softening. The sodium and chloride ions present in the
regeneration
waste water stream are monovalent ions and are not removed by the EC process
and
significantly impact the TDS of the regenerant waste water. High TDS of the
regenerant waste water will impact the total TDS and chloride concentration of
the
BFVV somewhat depending upon regenerant waste water volume and rate of
recycle.
For thermal heavy oil produced waters the TDS and chloride concentrations are
typically low enough to enable recycle of the regeneration waste water while
maintaining a BFW chloride concentration below the maximum target
concentration
of 5770 mg/L for OTSGs producing at least 90% steam quality.
22
CA 2962834 2017-03-30
[0091] The softened BFW 419 may be deaerated using a steam deaerator 415
before
being stored in a BFW storage tank 425 prior to steam generation. Steam to the
deaerator may be supplied from the medium and/or low pressure steam separators
430 located in the steam plant 60. The deaerated BFW 427 out of the BFW
storage
tank 425 may be treated with an oxygen scavenger 72 to remove trace oxygen to
less
than 0.007 ppm and if necessary caustic 70 to adjust the pH to 9.0 to meet
boiler
feedwater guidelines, producing a water feed 429 to the steam generators.
[0092] Steam generation stage 60 may be used to convert the water in
boiler feed
water stream 52 to steam, such as by using once through steam generators 435,
as
noted above. The OTSG steam generators 435, which may or may not be fitted
with
rifle tubes in up to 50% of the latter part of the radiant section, may be
used to
produce 90% or greater steam quality. Combusted fuel, stack gas 66, resulting
from
the steam generation process may be output via stack 440.
[0093] Steam generated in steam generation system 60 may be provided to
the
enhanced oil recovery system 445 via flow line 62. During startup, steam and
water
from steam generator 435 may be routed to a startup blowdown pond 450 via flow
line 68. A portion 461 of the boiler feed water 427/429 may also be combined
with
steam stream 364 in a de-superheater 430 to produce low and/or medium pressure
steam for feed to the deaerator 415 via flow line 58, and to other uses via
one or
more steam lines 64. For CSS or Steam Flood facilities, all of the 90% quality
steam that the OTSG produces may be sent to the field 445 for injection.
[0094] Referring now to Figure 5, a block process flow diagram of a front-
to-back
central processing facility for a CSS enhanced oil recovery system according
to
embodiments herein is illustrated, illustrating other embodiments of steps 50
and 60
of Figure 1 in greater detail, where like numerals represent like parts.
[0095] The clarified water fractions 44, 44B may be fed to the clean
backwash water
storage tank and low hardness removal stage 50, which may include an ion
exchange
system 410 and a de-aerator 415 in some embodiments. The "polishing" system 50
may reduce a total hardness of the clarified water fraction to less than 0.2
ppm, for
example, producing a regeneration waste water stream 28 and a boiler feed
water
stream 52.
23
CA 2962834 2017-03-30
[0096] The effluent 44, 44B from the EC process and filtration system may
contain
hardness that requires removal using Weak Acid Cation (WAC) polishers to an
acceptable BFW concentration of less than 0.2 ppm. The WAC units 410 are
operated in the Sodium (Nat) form and are regenerated in-situ with dilute HC1
(acid)
to remove the exchanged hardness then converted to the Na + form with dilute
NaOH
(caustic). Ion exchange regen chemicals may be fed to system 50 via flow line
54,
and Boiler Feed Water 44B may be used to dilute the concentrated chemicals 54
delivered to the plant to prepare the chemical regenerants.
[0097] The regeneration waste water 417 generated in the ion exchange
system 410
may be pH adjusted to neutrality in a neutralization tank 420 with additional
acid or
caustic then recycled in a slow controlled manner via flow line 28 to the
inlet of the
HT EC cells 30 while in operation or mixed with the incoming produced water
217
in the skim tank 220 or optional deoiled / make-up water storage tank 230
(each in
Figure 2). When the regeneration waste water hardness is processed by the EC
unit
30, the majority of the hardness contaminants are removed as solids to a level
required for ion exchange. This recycle treatment feature eliminates the need
for a
dedicated waste disposal well for the regeneration waste water or the use of
costly
chemicals to precipitate the waste dissolved hardness by lime softening. The
sodium
and chloride ions present in the regeneration waste water stream are
monovalent
ions and are not removed by the EC process and significantly impact the TDS of
the
regenerant waste water. High TDS of the regenerant waste water will impact the
total TDS and chloride concentration of the BFW somewhat depending upon
regenerant waste water volume and rate of recycle. For thermal heavy oil
produced
waters the TDS and chloride concentrations are typically low enough to enable
recycle of the regeneration waste water while maintaining a BFW chloride
concentration below the maximum target concentration of 5770 mg/L for OTSGs
producing at least 90% steam quality.
[0098] The softened BFW 419 may be deaerated using a steam deaerator 415
before
being stored in a BFW storage tank 425 prior to steam generation. Steam 58 to
the
deaerator may be supplied from the medium and/or low pressure steam separators
430 located in the steam plant 60. The deaerated BFW 427 out of the BFW
storage
tank 425 may be treated with an oxygen scavenger 72 to remove trace oxygen to
less
24
CA 2962834 2017-03-30
than 0.007 ppm and if necessary caustic 70 to adjust the pH to 9.0 to meet
boiler
feedwater guidelines, producing a water feed 429 to the steam generators.
[0099] Steam generation stage 60 may be used to convert the water in
boiler feed
water stream 429 to steam, such as by using once through steam generators 435,
as
noted above. The OTSG steam generators 435, which may or may not be fitted
with
rifle tubes in up to 50% of the latter part of the radiant section, may be
used to
produce 90% or greater steam quality. Combusted fuel, stack gas 66, resulting
from
the steam generation process may be output via stack 440.
[00100] Steam generated in steam generation system 60 may be provided to
the
enhanced oil recovery system 445 via flow line 62. For CSS or Steam Flood
facilities, all of the 90% quality steam that the OTSG produces may be sent to
the
field 445 for injection.
[00101] During startup, steam and water from steam generator 435 may be
routed to a
startup blowdown pond 450 via flow line 68. A portion 461 of the boiler feed
water
427/429 may also be combined with steam stream 364 in a de-superheater 430 to
produce low and/or medium pressure steam for feed to the deaerator 415 via
flow
line 58, and to other uses via one or more steam lines.
[00102] As illustrated in Figure 5, the CSS FTB-CPF embodiment illustrated
may be
used to maximize water reuse and minimize disposal. Steam from desuperheater
430 may be fed via flow line 462 to a multiple effect evaporator system 470
for TDS
reduction. A slip stream 472 of softened water may be combined with the steam
462, producing a vapor stream 474 and a water stream 476. The rate of the slip
stream 472 may be based on the target TDS in the boiler feed water. Water
stream
476 may be routed to a disposal well or treatment process 480. Optionally, a
crystallizer system 490 may be used to process water stream 476 along with
steam
489 for zero liquid discharge capability, producing a solids stream 67 to
landfill and
a steam stream 478, which may be processed with flash evaporator effluent 482
via
cooler 495, such as an aerial heat exchanger, the condensate 497 from which
may be
fed to deaerator 415 along with softened water 419 for further processing.
[00103] Referring now to Figure 6, a block process flow diagram of a front-
to-back
central processing facility for a CSS enhanced oil recovery system according
to
CA 2962834 2017-03-30
embodiments herein is illustrated, illustrating other embodiments of steps 50
and 60
of Figure 1 in greater detail, where like numerals represent like parts.
[00104] In this embodiment, the clarified water fractions 44, 44B may be
processed
and turned into steam in a manner similar to that described with respect to
Figures 4
and 5. Steam generation stage 60 may be used to convert the water in boiler
feed
water stream 52 to steam, such as by using once through steam generators 435,
as
noted above. The OTSG steam generators 435, which may or may not be fitted
with
rifle tubes in up to 50% of the latter part of the radiant section, may be
used to
produce 90% or greater steam quality. Combusted fuel, stack gas 66, resulting
from
the steam generation process may be output via stack 440.
[00105] Steam generated in steam generation system 60 may be provided to
the
enhanced oil recovery system 445 via flow line 62. During startup, steam and
water
from steam generator 435 may be routed to a startup blowdown pond 450 via flow
line 68. A portion 461 of the boiler feed water 427/429 may also be combined
with
steam stream 364 in a de-superheater 430 to produce low and/or medium pressure
steam for feed to the deaerator 415 via flow line 58, and to other uses.
[00106] As illustrated in Figure 6, the CSS FTB-CPF embodiment illustrated
may be
used to maximize water reuse and minimize disposal. The CSS FTB-CPF
embodiment of Figure 6 may maximize water reuse and minimize disposal, and
includes additional treatment utilizing a multiple effect evaporator system
470 with
an optional stack gas scrubber 500 and/or an optional crystallizer system 490
to:
meet regulatory guidelines; achieve near ZLD capability; Participate in a
Green
House Gas emission reduction initiative to receive carbon credits or reduce
carbon
taxes; and/or achieve ZLD capability.
[00107] As illustrated, steam from desuperheater 430 may be fed via flow
line 462 to a
multiple effect evaporator system 470 for TDS reduction. A slip stream 472 of
softened water may be combined with the steam 462, producing a vapor stream
474
and a water stream 476. The rate of the slip stream 472 may be based on the
target
TDS in the boiler feed water.
[00108] Water stream 476 may be routed to a scrubber 500, contacting a slip
stream
66B of the stack gas from stack 440. Scrubber 500 may be used to contact the
water
stream 476 with the stack gas to reduce greenhouse gas emissions and reduce
the pH
26
CA 2962834 2017-03-30
of the water 476 from the multi-effect evaporator 470. The pH adjusted water
502
may then be fed to a disposal well or treatment process 480. Optionally, a
crystallizer system 490 may be used to process water stream 502 along with
steam
489 for zero liquid discharge capability, producing a solids stream 67 to
landfill and
a steam stream 478, which may be processed with flash evaporator effluent 482
via
cooler 495, such as an aerial heat exchanger, the condensate 497 from which
may be
fed to deaerator 415 along with softened water 419 for further processing.
[00109] The block flow diagram of Figure 7 provides an overview of a
front-to-back
central processing facility for a SAGD enhanced oil recovery system according
to
embodiments herein. Figure 7, similar to other figures herein, is a block flow
diagram, illustrating primary steps in the SAGD FTB-CPF designs according to
embodiments herein.
[00110] The front-to-back central processing facility for a SAGD
enhanced oil
recovery system as illustrated in Figure 7 may also include six primary
stages,
including primary gas-oil-water separation stage 710, a high quality de-oiling
stage
720, high temperature electrocoagulation stage 730, waste separation and
solids/froth/sludge dewatering stage 740, low hardness removal and boiler feed
water storage stage 750, and steam generation stage 760.
[00111] A produced emulsion 712, such as an oil-water emulsion from a
SAGD
enhanced oil recovery system, is fed to an inlet of the gas-oil-water
separation stage
710. The produced oil-water emulsion may be provided directly or indirectly
from a
SAGD enhanced oil recovery system, and may include one or more of dissolved
solids, entrained gases and/or light hydrocarbons, distillate and/or heavier
hydrocarbons, and/or water. In primary gas-oil-water separation stage 710, the
emulsion is treated so as to separate the entrained gases and light
hydrocarbons from
the oil and water in the emulsion. The gases evolved may be fed via flow line
714 to
a vapor recovery unit (not shown) for further processing. The remaining oil-
water
emulsion may then be fed via flow line 716 to de-oiling stage 720.
[00112] De-oiling system 720 may separate the oil-water emulsion in
stream 716 into a
recovered oil fraction 722 and a water fraction 724. Water fraction 724 may
contain, among other components, dissolved silica, hardness, total organic
carbon,
and other dissolved organic and inorganic contaminants. To
facilitate the
27
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separations, a hydrocarbon solvent 725 may be used to reduce a density and
viscosity of the hydrocarbons in the oil-emulsion fraction and forming an oil
fraction
and a water-oil suspension containing residual oil.
[00113] To maintain an inert atmosphere in various tanks and other unit
operations in
the de-oiling system, a blanket gas, such as nitrogen, may be provided via
flow line
726. The vapors recovered from the tank and unit operation vents may be
recovered
via one or more flow lines 723 and fed to a vapor recovery unit, such as a
common
vapor recovery unit with the primary gas-oil-water separations, for recovery
or
further processing of the vapor streams, including any water, vaporized
solvent, and
light hydrocarbons therein.
[00114] Other feed streams to the de-oiling system may include a water
feed 727,
which may be used to provide fresh ground, brackish, or make-up water to the
system. Lastly, a neutralized regen waste recycle stream 728 may be provided
from
low hardness removal and boiler feed water storage stage 750 for further
processing
through the SAGD FTB-CPF.
[00115] The
water fraction 724 may then be fed to high temperature electrocoagulation
system 730. The
high temperature electrocoagulation system for ionizing,
complexing, and/or absorbing the dissolved silica, hardness, total organic
carbon,
and other dissolved organic and inorganic contaminants in the water fraction,
producing a vapor fraction 732 and a solids/froth/water mixture 734. Chemicals
used to pre-treat the feed to the high temperature electrocoagulation unit may
be
supplied via flow line 736. A recycle stream 738, such as a filtrate recycle
from
waste separation and froth/sludge dewatering stage 740 may also be provided to
the
high temperature electrocoagulation system.
[00116] Water separation and froth/sludge dewatering system 740 may
separate the
solids/froth/water mixture 734 into a sludge fraction 742, which may include
filtered
solids, and a clarified water fraction 744. A vapor stream 746 may also be
recovered
from water separation and froth/sludge dewatering stage 740, and processed in
the
above-noted vapor recovery unit. Sludge conditional chemicals, if used, may be
fed
to water separation and froth/sludge dewatering system 740 via flow line 748.
[00117] The clarified water fraction 744 may then be fed to low
hardness removal and
boiler feed water storage stage 750. The "polishing" system may reduce a total
28
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hardness of the clarified water fraction to less than 0.2 ppm, for example,
producing
a regeneration waste water stream 728 and a boiler feed water stream 752. Ion
exchange regen chemicals may be fed to system 750 via flow line 754, and vent
gases recovered via flow line 756 may be processed in the vapor recovery unit,
as
noted above. Steam used in the low hardness removal and boiler feed water
storage
stage 750 may be supplied from the steam generation stage 760 via flow line
758.
[00118] Steam generation stage 760 may be used to convert the water in
boiler feed
water stream 752 to steam, such as by using once through steam generators, as
noted
above. Steam generated in steam generation system 760 may be provided to the
enhanced oil recovery system (not shown) via flow line 762, to the low
hardness
removal and boiler feed water storage stage 750 via flow line 758, and to
other uses
via one or more steam lines 764. Other outputs from steam generation stage 760
may include OTSG stack gas 766, solids / landfill waste stream 767, and
blowdown
water 768 to a disposal well or treatment process (not shown). As needed,
boiler
feed water conditioner 770 and oxygen scavenger 772 may be introduced to the
steam generation system 760 as well. The SAGD FTB-CPF may also include a
volatile amine or ammonia feed 780, as well as a water recycle stream 782 fed
to the
high temperature electrocoagulation system 30 along with the filtrate recycle
stream
738.
[00119] Various steps within each of the noted system blocks illustrated in
Figure 7 are
described above, and below in Figures 8-14, and as such are not described in
detail
with respect to Figure 7. Figure 7 simply provides a general overview of the
various
systems used in the FTB-CPF according to embodiments herein that may be used
with a SAGD enhanced oil recovery system.
[00120] Referring now to Figure 8, a block process flow diagram of a front-
to-back
central processing facility for a SAGD enhanced oil recovery system according
to
embodiments herein is illustrated, illustrating embodiments of steps 710 and
720 of
Figure 7 in greater detail, where like numerals represent like parts.
[00121] A produced emulsion 712, such as an oil-water emulsion from a SAGD
enhanced oil recovery system, is fed to an inlet of the gas-oil-water
separation stage
710. The produced oil-water emulsion may be provided directly or indirectly
from a
SAGD enhanced oil recovery system, and may include one or more of dissolved
29
CA 2962834 2017-03-30
solids, entrained gases and/or light hydrocarbons, distillate and/or heavier
hydrocarbons, and/or water. In primary gas-oil-water separation stage 710, the
emulsion may be treated initially in a Free Water Knockout (FWKO) drum 810 to
separate the entrained gases and light hydrocarbons from the oil and water in
the
emulsion. The gases evolved may be fed via flow line 714 to a vapor recovery
unit
(not shown) for further processing. The remaining oil-water emulsion may then
be
fed via flow line 716 to de-oiling stage 720.
[00122] Deoiling system 720 may separate the oil-water emulsion in stream
716 into a
recovered oil fraction 722 and a water fraction 724. Water fraction 724 may
contain, among other components, dissolved silica, hardness, total organic
carbon,
and other dissolved organic and inorganic contaminants. In de-oiling system
720,
oil-water emulsion 716 may be fed to an Oil Treater (OT) 815 for recovery of
oil
from water. To facilitate the separations in OT 815, a hydrocarbon solvent 725
may
be used to reduce a density and viscosity of the hydrocarbons in the oil-
emulsion
fraction and forming an oil fraction 722 and a water-oil suspension (produced
water)
817 containing residual oil.
[00123] The produced water 817 recovered from the FWKO 810 and OT 815 may
be
cooled to less than 95 C through heat exchange with OTSG BFW and (if needed)
an
aerial or glycol cooler (one or more exchangers 819). The produced water 817
from
OT 815 is transferred to a skim/surge tank (ST) 820, and may contain an
average of
2000 ppm of residual oil, in some embodiments, less than 3000 ppm or less than
3500 ppm in other embodiments, with excursions that may exceed 5000 ppm for
short periods.
[00124] The produced water-oil suspension 817 in the feed to ST 820 may be
chemically treated to enhance coalescence of the oil droplets to effect more
rapid
gravity separation of the oil that rises to the surface in the tank. The ST
820 may be
designed to reduce the oil in water concentration in the effluent to 10% of
the inlet
concentration. The oil separated in ST 820 is skimmed off and returned via
flow line
822 to one of OT 815, FWKO 810, or an oil recovery/slop tank (not illustrated)
for
additional treatment and dewatering.
[00125] ST 820 effluent 824 may be further de-oiled with a dissolved gas
floatation
unit (DGF) 825. The dissolved gas floatation unit 825 may be designed to
reduce the
CA 2962834 2017-03-30
oil in water to less than 10 ppm, for example. Oil that is separated from the
water
and skimmed off from the DGF unit may be returned via flow line 827 to the
skim
tank 820 or transferred to a recovery/slop oil tank (not shown).
[00126] The deoiled produced water 829 from the DGF unit 825 may be
transferred to
an optional deoiled / makeup water storage tank 830, where the deoiled product
may
be thoroughly mixed with filtered makeup water 727 from groundwater or surface
water sources (with or without pH adjustment) and recycled neutralized weak
acid
cation exchange regenerant waste water 728 prior to being transferred to the
high
temperature electrocoagulation process (Figure 9) via flow line 24.
[00127] To maintain an inert atmosphere in various tanks and other unit
operations in
the de-oiling system, a blanket gas, such as nitrogen, may be provided via
flow line
726. The vapors recovered from the tank and unit operation vents may be
recovered
via one or more flow lines 723 and fed to a vapor recovery unit, such as a
common
vapor recovery unit with the primary gas-oil-water separations vent 714, for
recovery or further processing of the vapor streams 714, 726, including any
water,
vaporized solvent, and light hydrocarbons therein.
[00128] Referring now to Figure 9, a block process flow diagram of a front-
to-back
central processing facility for a SAGD enhanced oil recovery system according
to
embodiments herein is illustrated, illustrating embodiments of steps 730 and
740 of
Figure 7 in greater detail, where like numerals represent like parts.
[00129] The water fraction 724 may be fed to high temperature
electrocoagulation
system 730. The high temperature electrocoagulation system 730 may be
configured for ionizing, complexing, and/or absorbing the dissolved silica,
hardness,
total organic carbon, and other dissolved or inorganic contaminants in the
water
fraction, producing a vapor fraction 732 and a solids/froth/water mixture 734.
The
blended water 724 from the deoiled/makeup water storage tank is pumped and
evenly distributed to the required correctly sized number of operating
electrocoagulation ("EC") cells in high temperature EC system 730. As noted
above,
the EC cells may hold iron or aluminum electrode plates, for example. DC power
is
supplied to the cells to deliver up to 7 kw/m3 of throughput with iron or
aluminum
electrode consumption by the process typically between 0.02 to 0.03 kg/m3 of
treated water.
31
CA 2962834 2017-03-30
[00130] Chemicals used to pre-treat the feed to the high temperature
electrocoagulation
unit may be supplied via flow line 736. A recycle stream 738, such as a
filtrate
recycle from clean boiler water storage tank 920 in waste separation and
froth/sludge dewatering stage 740 may also be provided to the high temperature
electrocoagulation system.
[00131] The power supply polarity across the plates may be reversed
periodically to
help prevent deposits from building up on the plates. Additionally, in some
embodiments, the pH of the feed to the HT EC system may be modified to improve
or optimize EC contaminant removal efficiency. The electrode plates that
dissolve
during the EC process is simultaneously converted to a charged oxidized
particle
while ionizing, complexing, and/or absorbing dissolved silica, hardness, total
organic carbon and many other dissolved organic and inorganic contaminants,
including multivalent contaminants. This sequence promotes coagulation of the
free
suspended oil and solids that all combine and make up the composition of the
entrained suspended solids/froth 734. The solids/froth/water mixture 734 flows
out
of the EC cell into a collection trough (not shown) that feeds the downstream
solids/froth water separation unit 925. The HT EC cell 730 and the trough may
be
fitted with a vapor containment cover to direct any gases or vapors generated
via
flow line 732 to a dedicated knockout drum and discharge vent or recovered for
fuel
gas or disposal using a Vapor Recovery Unit (VRU) (not shown), which may be
the
same or different VRU than that used with respect to stages 710 and 720. The
HT
EC unit 730 design may include the option to inject air or inert gas 923 into
the
bottom of the cell to promote floatation and removal of the solids\froth
generated.
Fugitive toxic gas emissions are not expected to exceed regulatory limits but
may be
recovered through the use of the VRU.
[00132] The electrode plates and EC cells are cleaned, "pickled,"
sequentially and
routinely to maintain electrocoagulation energy efficiency using a dilute HC1
or
H2SO4 acid clean-in-place (OP) solution stored in a separate single tank 929
dedicated to service all EC cells. The ClP solution is used over and over
until the
acid strength is depleted at which time the exhausted solution is pH
neutralized and
directed back, at a steady controlled rate, into the feed distribution line to
the EC
32
CA 2962834 2017-03-30
cells for treatment, where the contaminants in the solution are removed as
solids/froth 734.
[00133] Water separation and solids/froth/sludge dewatering system 740 may
separate
the solids/froth/water mixture 734 into a sludge fraction 742, which may
include
filtered solids, and a clarified water fraction 744. A vapor stream 746 may
also be
recovered from water separation and froth/sludge dewatering stage 740, and
processed in the above-noted vapor recovery unit. Sludge conditional
chemicals, if
used, may be fed to water separation and froth/sludge dewatering system 740
via
flow line 748.
[00134] As illustrated in Figure 9, the HT EC effluent, solids-froth-water
mixture 734,
nay be fed into to a three stage enclosed sequential cascading solids/froth
breaking
(defoaming) cell 925. The solids/froth breaker 925 uses strategically designed
spreaders and water sprays to break the froth and release the trapped solids,
producing a solids entrained water effluent 931 with no froth or foam.
[00135] The solids entrained water 931 passes through hydrocyclones 930,
which may
be designed to maximize the removal of fine entrained solids, such as
particles as
small as 10 micron in size, and reduce the clarified solids concentration in
the
resulting effluent 937 to less than 30 mg/L. The hydrocyclone system 930 may
include provisions to include coagulation of flocculation upstream or
downstream to
further maximize solids particle size, removal and subsequent filtration
efficiency.
The separated solids collected in the bowl of the hydrocyclone unit are
discharged
via flow line 939, as required, and sent to a surge tank and filter press 940
for final
dewatering and subsequent landfill of solids 742. Off spec water 936 from the
hydrocyclones may be treated with chemical and may be recycled back through
the
EC system (as shown) or defoaming unit via the filter dirty backwash storage
tank
for re-processing or sent through a secondary off-spec polishing hydrocyclone
unit
(not shown).
[00136] The clarified separated water 937 from hydrocyclone 930 is then
filtered using
micro-media filters 945 or alternatively ultrafiltration membranes to remove
trace
solids from the clarified water. The filters 945 may be designed to produce an
effluent having a turbidity value of less than 2 and a solids content of less
than 1
ppm. When solids loading on the micro media filters 945 create a pressure drop
that
33
CA 2962834 2017-03-30
reduces the throughput capacity of the filters, the filter media is air or gas
scoured
and then backwashed. Should an ultrafiltration system be utilized the
membranes are
constantly discharging a concentrated slurry to the dirty backwash tank and
undergo
a high pressure back pulse intermittently to dislodge entrapped solids within
the
membrane lattice. Filtrate from the media filters supplies clean backwashing
(BW)
water to the clean BW water storage tank. The dirty backwash or slurry stream
from
the filtration system backwashing sequence is sent to a dirty backwash tank
then
recycled back to the inlet of the solids/froth defoaming cell. Intermittent
chemical
cleaning via clean-in-place system 946 combined with air scour cleaning of the
micro-media filter media is optional and may be used as required to maintain
media
quality and filter performance.
[00137] The clarified water fraction 744 may then be fed to a clean
backwash water
storage tank and low hardness removal stage 750 (Figure 10) and boiler feed
water
storage tank 920. One or more water storage tanks 920 may be used to provide a
water stream 738 to the HT EC unit 730, as well as feed 744B to stage 750, as
a
supply of water 948 for backwash of the filtration system 945, and as a supply
954
of water to filter press 940, as needed. For example, a first tank 920 may be
used to
supply dilution water for the chemicals required for regeneration of the ion
exchangers, and clean service water may be provided from a clean backwash
water
storage tank 920 to provide service water to the HC EC unit (rinse after CIP
treatment), Defoaming Cell, Filter Press and backwashing of the media filters.
Water
recovered from the dewatering filter press 940 may be returned via flow line
952 to
either HT EC unit 730 or filtration unit 945 for further processing.
[00138] Referring now to Figure 10, a block process flow diagram of a front-
to-back
central processing facility for a SAGD enhanced oil recovery system according
to
embodiments herein is illustrated, illustrating embodiments of steps 50 and 60
of
Figure 7 in greater detail, where like numerals represent like parts.
[00139] The clarified water fractions 744, 744B may be fed to low hardness
removal
stage 750, which may include a clean backwash water storage tank, an ion
exchange
system 1010 and a de-aerator 1015 in some embodiments. The "polishing" system
750 may reduce a total hardness of the clarified water fraction to less than
0.2 ppm,
34
CA 2962834 2017-03-30
for example, producing a regeneration waste water stream 728 and a boiler feed
water stream 752.
[00140] The effluent 744, 744B from the EC process and filtration system
(Figure 9)
may contain hardness that requires removal using Weak Acid Cation (WAC)
polishers to an acceptable BFW concentration of less than 0.2 ppm. The WAC
units
1010 are operated in the Sodium (Nat) form and are regenerated in-situ with
typically dilute HC1 acid to remove the exchanged hardness then converted to
the
Nat form with dilute NaOH (caustic). Ion exchange regen chemicals may be fed
to
system 750 via flow line 754, and Boiler Feed Water 744B may be used to dilute
the
concentrated chemicals delivered to the plant to prepare the chemical
regenerants.
[00141] A unique feature of the SAGD FTB-CPF design is the recycling and
treatment
of the regeneration waste water. The regeneration waste water 1017 generated
in the
ion exchange system 1010 may be pH adjusted to neutrality in a neutralization
tank
1020 with additional acid or caustic then recycled in a slow controlled manner
via
flow line 728 to the inlet of the HT EC cells 730 while in operation or mixed
with
the incoming produced water 817 in the skim tank 820 or optional deoiled /
make-up
water storage tank 830 (each in Figure 2). When the regeneration waste water
hardness is processed by the EC unit 730, the majority of the hardness
contaminants
are removed as solids to a level required for ion exchange. This recycle
treatment
feature eliminates the need for a dedicated waste disposal well for the
regeneration
waste water or the use of costly chemicals to precipitate the waste dissolved
hardness by lime softening. The sodium and chloride ions present in the
regeneration
waste water stream are monovalent ions and are not removed by the EC process
and
significantly impact the TDS of the regenerant waste water. High TDS of the
regenerant waste water will impact the total TDS and chloride concentration of
the
BFW somewhat depending upon regenerant waste water volume and rate of recycle.
For thermal heavy oil produced waters the TDS and chloride concentrations are
typically low enough to enable recycle of the regeneration waste water while
maintaining a BFW chloride concentration below the maximum target
concentration
of 5770 mg/L for OTSGs producing at least 90% steam quality.
[00142] The softened BFW 1019 may be deaerated using a steam deaerator 1015
before being stored in a BFW storage tank 1025 prior to steam generation.
Steam to
CA 2962834 2017-03-30
the deaerator may be supplied from the medium and/or low pressure steam
separators 1030 located in the steam plant 760. The deaerated BFW 1027 out of
the
BFW storage tank 1025 may be treated with an oxygen scavenger 772 to remove
trace oxygen to less than 0.007 ppm and if necessary caustic 770 to adjust the
pH to
9.0 to meet boiler feedwater guidelines, producing a water feed 1029 to the
steam
generators.
[00143] Steam generation stage 760 may be used to convert the water in
boiler feed
water stream 752 to steam, such as by using once through steam generators
1035, as
noted above. The OTSG steam generators 1035, which may or may not be fitted
with rifle tubes in up to 50% of the latter part of the radiant section, may
be used to
produce 90% or greater steam quality. Combusted fuel, stack gas 766, resulting
from the steam generation process may be output via stack 1040.
[00144] Steam generated in steam generation system 760, as noted above, is
of 90% or
greater steam quality. The resulting 90% steam phase 1036 is separated from
the
liquid phase by a high pressure separator (HPS) 1042 to deliver 100% quality
steam
to the SAGD enhanced oil recovery system 1045 via flow line 762. At SAGD
facilities, a volatile-filming amine 1050 may be injected via feed system 1052
into
the 100% steam to field distribution line as to control the potential for
carbonic acid
corrosion in the line. An alternative option may be used for the FTB CPF
designs
according to embodiments herein, where liquefied ammonia may be used to
provide
similar corrosion protection.
[00145] For SAGD facilities where the HPS produces blowdown (BD) 1044, the
HP
BD pressure is let down in a medium pressure (MP) and/or a low pressure (LP)
steam separator 1060. The MP plus LP steam separators 1060 together can
convert
up to 40% of the water to MP and LP steam 758 that is used to operate the BFW
steam deaerator 1015. Excess utility steam, if any, may be cooled in one or
more
exchangers 1090 and the condensate routed to the boiler feed water storage
tank
1025.
[00146] Condensate blowdown 1065 from steam separators 1060 may be
forwarded to
disposal tanks 1070, and thence via line 1072 to a disposal well or treatment
process
1080. If the boiler feed water TDS is below 5500, it may be possible to route
the
blowdown 1065 back to the HT EC cell 730 for further processing.
36
CA 2962834 2017-03-30
[00147] Referring now to Figure 11, a block process flow diagram of a front-
to-back
central processing facility for a SAGD enhanced oil recovery system according
to
embodiments herein is illustrated, illustrating other embodiments of steps 750
and
760 of Figure 7 in greater detail, where like numerals represent like parts.
[00148] In this embodiment, the clarified water fractions 744, 744B may be
processed
and turned into steam in a manner similar to that described with respect to
Figure 10.
Steam generation stage 760 may be used to convert the water in boiler feed
water
stream 752 to steam, such as by using once through steam generators 1035, as
noted
above. The OTSG steam generators 1035, which may or may not be fitted with
rifle
tubes in up to 50% of the latter part of the radiant section, may be used to
produce
90% or greater steam quality. Combusted fuel, stack gas 766, resulting from
the
steam generation process may be output via stack 1040.
[00149] Steam generated in steam generation system 760, as noted above, is
of 90% or
greater steam quality. The resulting 90% steam phase 1036 is separated from
the
liquid phase by a high pressure separator (HPS) 1042 to deliver 100% quality
steam
to the SAGD enhanced oil recovery system 1045 via flow line 762. At SAGD
facilities, a volatile-filming amine 1050 may be injected via feed system 1052
into
the 100% steam to field distribution line as to control the potential for
carbonic acid
corrosion in the line. An alternative option may be used for the FTB CPF
designs
according to embodiments herein, where liquefied ammonia may be used to
provide
similar corrosion protection.
[00150] For SAGD facilities where the HPS produces blowdown (BD) 1044, the
HP
BD pressure is let down in a medium pressure (MP) and/or a low pressure (LP)
steam separator 1060. The MP plus LP steam separators 1060 together can
convert
up to 40% of the water to MP and LP steam 758 that is used to operate the BFW
steam deaerator 1015. Condensate blowdown 1065 from steam separators 1060 may
be forwarded to disposal tanks 1070, and thence via line 1072 to a disposal
well or
treatment process 1080.
[00151] As illustrated in Figure 11, the CSS FTB-CPF embodiment illustrated
may be
used to maximize water reuse and minimize disposal. A portion of steam stream
758, utility steam stream 1110, may be fed to a multiple effect evaporator
system
1120 for TDS reduction. A slip stream 1073 of softened water, and optionally a
37
CA 2962834 2017-03-30
portion of blowdown stream 1072 may be combined with the steam 1110, producing
a vapor stream 1074 and a water stream 1076. The rate of the slip stream 1072
may
be based on the target TDS in the boiler feed water. Water stream 1076 may be
routed to a disposal well or treatment process 1080. Vapor stream 1074 may be
condensed via one or more exchangers 1090 and returned via line 1092 to the
steam
deaerator 1015 for further processing. As a further option, steam 1148 from
phase
separator 1042 may be provided to a de-superheater 1150, contacting boiler
feed
water slip stream 1157 to produce additional low or medium pressure steam 1159
for
use in evaporator 1120 or deaerator 1015.
[00152] Referring now to Figure 12, a block process flow diagram of a
front-to-back
central processing facility for a SAGD enhanced oil recovery system according
to
embodiments herein is illustrated, illustrating other embodiments of steps 750
and
760 of Figure 7 in greater detail, where like numerals represent like parts.
[00153] In this embodiment, the clarified water fractions 744, 744B may be
processed
and turned into steam in a manner similar to that described with respect to
Figures
and 11. Steam generation stage 760 may be used to convert the water in boiler
feed water stream 752 to steam, such as by using once through steam generators
1035, as noted above. The OTSG steam generators 1035 may be used to produce
90% or greater steam quality. Combusted fuel, stack gas 766, resulting from
the
steam generation process may be output via stack 1040.
[00154] Steam generated in steam generation system 760, as noted above, is
of 90% or
greater steam quality. The resulting 90% steam phase 1036 is separated from
the
liquid phase by a high pressure separator (HPS) 1042 to deliver 100% quality
steam
to the SAGD enhanced oil recovery system 1045 via flow line 762. At SAGD
facilities, a volatile-filming amine 1050 may be injected via feed system 1052
into
the 100% steam to field distribution line as to control the potential for
carbonic acid
corrosion in the line. An alternative option may be used for the FTB CPF
designs
according to embodiments herein, where liquefied ammonia may be used to
provide
similar corrosion protection.
[00155] For SAGD facilities where the HPS produces blowdown (BD) 1044, the
HP
BD pressure is let down in a medium pressure (MP) and/or a low pressure (LP)
steam separator 1060. The MP plus LP steam separators 1060 together can
convert
38
CA 2962834 2017-03-30
up to 40% of the water to MP and LP steam 758 that is used to operate the BFW
steam deaerator 1015.
[00156] As illustrated in Figure 12, the SAGD FTB-CPF embodiment
illustrated may
be used to maximize water reuse and minimize disposal. A portion of steam
stream
758, utility steam stream 1110, and blowdown stream 1072 may be fed to a
multiple
effect evaporator system 1120 for TDS reduction, producing a vapor stream 1074
and a water stream 1076.
[00157] Vapor stream 1074 may be condensed via one or more exchangers 1090
and
returned via line 1092 to the steam deaerator 1015 for further processing.
Water
stream 1076 may be routed to a disposal well or treatment process 1080. If the
boiler feed water TDS is below 5500, it may be possible to route the water
stream
1076 via line 1077 back to the HT EC cell 730 for further processing.
[00158] Optionally, a crystallizer system 1290 may be used to process water
stream
1076 along with steam 1112 for zero liquid discharge capability, producing a
solids
stream 67 to landfill and a steam stream 1078, which may be processed with
flash
evaporator effluent 1074 via cooler 1090, such as an aerial heat exchanger,
the
condensate 1092 from which may be fed to deaerator 1015 along with softened
water 1019 for further processing.
[00159] As a further option, steam 1148 from phase separator 1042 may be
provided to
a de-superheater 1150, contacting boiler feed water slip stream 1157 to
produce
additional low or medium pressure steam 1159 for use in evaporator 1120,
deaerator
1015, or crystallizer 1290.
[00160] Referring now to Figure 13, a block process flow diagram of a front-
to-back
central processing facility for a SAGD enhanced oil recovery system according
to
embodiments herein is illustrated, illustrating other embodiments of steps 750
and
760 of Figure 7 in greater detail, where like numerals represent like parts.
[00161] In this embodiment, the clarified water fractions 744, 744B may be
processed
and turned into steam in a manner similar to that described with respect to
Figure 10.
Steam generation stage 760 may be used to convert the water in boiler feed
water
stream 752 to steam, such as by using once through steam generators 1035, as
noted
above. The OTSG steam generators 1035, which may or may not be fitted with
rifle
tubes in up to 50% of the latter part of the radiant section, may be used to
produce
39
CA 2962834 2017-03-30
90% or greater steam quality. Combusted fuel, stack gas 766, resulting from
the
steam generation process may be output via stack 1040.
[00162] Steam generated in steam generation system 760, as noted above, is
of 90% or
greater steam quality. The resulting 90% steam phase 1036 is separated from
the
liquid phase by a high pressure separator (HPS) 1042 to deliver 100% quality
steam
to the SAGD enhanced oil recovery system 1045 via flow line 762. At SAGD
facilities, a volatile-filming amine 1050 may be injected via feed system 1052
into
the 100% steam to field distribution line as to control the potential for
carbonic acid
corrosion in the line. An alternative option may be used for the FTB CPF
designs
according to embodiments herein, where liquefied ammonia may be used to
provide
similar corrosion protection.
[00163] For SAGD facilities where the HPS produces blowdown (BD) 1044, the
HP
BD pressure is let down in a medium pressure (MP) and/or a low pressure (LP)
steam separator 1060. The MP plus LP steam separators 1060 together can
convert
up to 40% of the water to MP and LP steam 758 that is used to operate the BFW
steam deaerator 1015.
[00164] Condensate blowdown 1065 from steam separators 1060 may be routed
to a
scrubber 1300, contacting a slip stream 766B of the stack gas from stack 1040.
Scrubber 1300 may be used to contact the water stream 1065 with the stack gas
to
reduce greenhouse gas emissions and reduce the pH of the water 1065. The pH
adjusted water 1302 may then be fed to a disposal well or treatment process
1080. If
the boiler feed water TDS is below 5500, it may be possible to route the pH
adjusted
water stream 1302 via line 1077 back to the HT EC cell 730 for further
processing.
[00165] Referring now to Figure 14, a block process flow diagram of a front-
to-back
central processing facility for a SAGD enhanced oil recovery system according
to
embodiments herein is illustrated, illustrating other embodiments of steps 750
and
760 of Figure 7 in greater detail, where like numerals represent like parts.
In this
embodiment, the clarified water fractions 744, 744B may be processed and
turned
into steam, and the steam processed in a manner similar to that described with
respect to Figures 12, including the multi-effect evaporator 1120 and the
crystallizer
1290. Additionally in this embodiment, scrubber 1300 may be used to contact
the
water stream 1076 with the stack gas to reduce greenhouse gas emissions and
reduce
CA 2962834 2017-03-30
the pH of the water in stream 1076. The pH adjusted water 1302 may then be fed
to
a disposal well or treatment process 1080 or alternatively may be fed to
crystallizer
1090 for a zero liquid discharge option.
[00166] FTB ADD-ON DEBOTTLENECKING DESIGNS
[00167] The FTB-CPF designs disclosed herein has additionally fostered the
development of five FTB Add-On process debottlenecking and production
enhancement designs for the thermal heavy oil industry, described below. A
base
case as reference is provided. Add-On cases 1-3 integrate design features of
the
FTB-CPF water treatment processes according to embodiments herein within a
30,000 bopd lime softening ¨ OTSG CPF facility. Cases 4 and 5 were developed
to
resolve known production bottlenecks that may be encountered at thermal in-
situ
facilities. Variations of these Add-On debottlenecking designs or a
combination of
these can be utilized according to embodiments herein to retrofit most
existing
thermal heavy oil facilities
[00168] 30,000 bopd BASE CASE SAGD FACILITY
[00169] A 30,000 bopd Base Case SAGD facility with a steam to oil ratio of
3.0 was
used for reference to foster the development of debottlenecking FTB Add-On
designs.
The Base Case facility incorporates conventional Free Water Knockout and
Treater
oil separation units followed by a skim tank, induced gas floatation unit and
oil filters
for deoiling of hot produced water. The hot deoiled water with blended fresh
or
brackish makeup ground water is treated to BFW specs using a warm lime
softener to
remove primarily silica and hardness that is followed by filtration and then
ion
exchange for final hardness removal. The lime softener throughput is limited
to the
settling rate of the precipitated solids in the unit which for warm lime
softening as
shown is traditionally between 0.7 ¨ 1.2 usgpm/ft2 and for hot lime softening
(not
shown) is traditionally between 2 and 2.2 usgpm/ft2. All equipment downstream
of
the lime softener is sized to accommodate the maximum throughput of the lime
softening unit that often is unable to achieve the maximum throughput rates
thereby
creating a bottleneck in the water treatment process should additional steam-
to-field
capacity and increased oil production be the objective of the heavy oil
producer.
41
CA 2962834 2017-03-30
[00170] A block flow diagram illustrating the base case flow scheme is
provided in
Figure 15. The reference numerals and unit operations used in the base case
flow
diagram are provided in Table 1 below.
Table 1. Figure 15 unit operations and reference numbers.
Reservoir 1500 Produced Water 1502
Produced Water to 1503 Landfill / Disposal 1505
Sales Stream from Water
Treatment
Water Losses To 1504 Oil Treating 1506
reservoir
Preflash Vessel 1508 FWKO 1510
Treaters 1512 Vapor Recovery 1514
Diluent 1516 Diluted Bitumen 1518
Oil Recycle 1520 Deoiled Water 1522
Deoiling 1524 Skim Tank 1526
IGF/ISF/ORG units 1528 Water Treatment 1530
PW Tank 1532 WLS 1534
AF/WAC 1536 BFW Tank 1538
Steam Generation 1540 OTSGs 1542
HPS 1544 LP Flash 1546
Boiler Feed Water 1548 Wet Steam 1550
HP Steam 1552 Blowdown 1554
LPF Condensate 1556 Blowdown to 1558
Disposal
Blowdown Recycle 1559 Make-up Water 1561
Produced Water from 1560 Produced Water from 1562
FWKO Treaters
[00171] The base case conditions and results are shown in Table 2 below.
Table 2.
Reservoir
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CA 2962834 2017-03-30
SOR 3.00
GOR 5.00
Water Losses to Reservoir 9000
(bpd)
Bitumen
bpd 30000
API gravity 7.1
Produced Water from
Reservoir
bpd 81000
TDS (ppm) 1492
TH (ppm) 14
Silica (mg 5i02 /1) 188
Produced Water Sales (bpd) 200
Produced Gas MMSCFD 0.88
Water from Oil Treating bpd 80800
Make-up Water
bpd 18100
Si02 (ppm) 7
TDS 7200
TH 200
Deoiled Water bpd 80800
Water Treatment
Blowdown Recycle (bpd) 9900
Landfill / disposal (bpd) 1000
Boiler Feed Water
bpd 115400
TDS (ppm) <8000
Si02 (ppm) <50
TH (ppm) <0.5
Steam Generation
43
CA 2962834 2017-03-30
Wet Steam Quality (%) 78
Wet Steam bpd 115400
HP Steam Quality (%) 100
HP Steam bpd 90000
Blowdown (bpd) 25400
Condensate Recycle (bpd) 7600
Blowdown to Disposal (bpd) 7900
Blowdown TDS (ppm) <50900
Blowdown Si02 (ppm) <320
Blowdown TH (ppm) <3.0
[00172] The FTB Add-On debottlenecking designs were developed for all the
cases
included herein assuming that as a result of an increase in steam quality or
steam to
field, the oil separation and deoiling equipment are capable of processing an
increase
in the amount of oil water emulsion from the field or the equipment would be
modified and/or increased in quantity as required.
[00173] Case 1 ¨ Increase OTSG Steam Quality
[00174] The FTB-CPF Add-On CASE 1 design was developed to increase the
steam
quality generated by the OTSGs by 4% from the traditional operating level of
78%
and provide solutions to existing operating bottlenecks or to meet operating
cost
reduction objectives that included: (A) The lime softener throughput is not
able to
achieve maximum design treatment rates and BFW quantity to meet steam
production
targets; (B) The amount of blowdown from the OTSGs and subsequent recycle,
recovery and disposal of the blowdown fraction was insufficient for meeting
the
Alberta Energy Regulator targets; (C) The amount of fresh or brackish makeup
water
that is available and needed at the facility is insufficient to meet the BFW
supply
target; and (D) An objective to reduce the cost of fuel and future carbon
emission
taxes.
[00175] The Case 1 design specifies the use of a dual train EC system each
designed to
treat up to 36,400 bpd (136 m3/hr) of hot produced water followed by
defoaming,
dewatering, filtration and ion exchange processes. The BFW produces in a
higher
quality than what is being produced by the base case process. The higher
quality BFW
44
CA 2962834 2017-03-30
is attributed to the FTB-EC cells to deliver a reduction in the concentration
of silica
(Sia,) of up to 80% and a reduction in soluble total organic carbon (TOC) of
up to
50%. A reduction in these dissolved components together with hardness removal
results in a reduction in the rate of silicate and organic compound scale
deposition on
the internal surfaces of the OTSG tubing and potential tube failures while
improving
the OTSG heat transfer efficiency between generator inspection periods.
[00176] The high quality BFW produced by the FTB-CPF Add-On package is
blended
with the existing BFW produced by the Base Case water treatment processes to
achieve a silica reduction of up to 33% and a TOC reduction of up to 25%
thereby
enabling the OTSGs to increase the high pressure steam quality to 82% while
generating the same mass of steam to field using 4.9% less BFW.
[00177] Additional impacts of integrating this FTB-CPF Add-On design with
Base
Case plant operations include: (A) The lime softener throughput rate decreases
by up
to 38% based on a reduction of up to 45% in produced water feed and 12%
decrease
in the OTSG blowdown recycle rate to the lime softener; (B) Less BFW required
results in a 12% reduction in makeup water; and (C) The OTSG blowdown to
disposal is reduced by 34%.
[00178] A block flow diagram illustrating the Case 1 Add On flow scheme is
provided
in Figure 16. The reference numerals and unit operations used in the Case 1
Add On
flow diagram are provided in Table 3 below.
Table 3. Figure 16 unit operations and reference numbers.
Reservoir 1600 Produced Water to 1602
Sales
Water Losses To 1604 Produced Water 1606
reservoir (after degassing)
Deoiling 1608 Deoiled Water 1610
IGF/ISF/ORG units 1612 Skim Tank 1614
FTB Add On 1616 HT EC 1618
Solids Dewatering 1620 Solds-Water 1622
Separations
MicroFiltration 1624 WAC 1626
Boiler Feed Water 1628 Deaerator 1629
CA 2962834 2017-03-30
PW Tank 1632 Water Treatment 1630
AF/WAC 1636 WLS 1634
Steam Generation 1640 BFW Tank 1638
HPS 1644 OTSGs 1642
LP Flash 1648 Blowdown 1646
LP Blowdown to 1652 LPF Condensate 1650
Disposal Recycle
Wet Steam 1656 Blowdown Recycle 1654
Make-up Water 1660 HP Steam 1658
Solids to Landfill 1664 Landfill / Disposal 1662
Stream from Water
Treatment
Deaerator Steam 1666 Boiler Feed Water 1670
[00179] The Case 1
conditions and results are shown in Table 4 below.
Table 4.
Reservoir
SOR 3.00
GOR 5.00
Water Losses to Reservoir 9000
(bpd)
Bitumen
bpd 30000
API gravity 7.1
Produced Water from
Reservoir
bpd 81000
TDS (ppm) 1492
TH (ppm) 14
Silica (mg Si02 / I) 188
Produced Water Sales (bpd) 200
46
CA 2962834 2017-03-30
Produced Gas MMSCFD 0.88
Water from Oil Treating bpd 80800
to FTB add-on 36400
To existing water treatment 44400
Make-up Water
bpd 15000
Si02 (ppm) 7
TDS 7200
TH 200
Water Treatment
Blowdown Recycle (bpd) 8700
Landfill / disposal (bpd) 600
Boiler Feed Water
bpd 109800
Steam Generation
Wet Steam Quality (%) 82
Wet Steam bpd 109800
HP Steam Quality (%) 100
HP Steam bpd 90000
Blowdown (bpd) 19800
Condensate Recycle (bpd) 4800
Blowdown to Disposal (bpd) 5200
[00180] Compared to the base case, Case 1 provides a 4% increase in wet
steam
quality, requires 12% less make-up water, may decrease disposal by 34%, and
may
reduce landfill by about 40%.
[00181] FTB-CPF Add-On CASE 2 - Increase Steam Quantity to Field
[00182] The FTB-CPF Add-On CASE 2 design was developed to increase the
steam to
field generated by the OTSGs by 33% and correspondingly increase oil
production for
a heavy oil producer compared to the Base Case design. The Add-On includes the
addition of HT EC modules, solids dewatering, solids-water separation,
microfiltration, WAC, and a deaerator, similar to embodiments of one or more
of
47
CA 2962834 2017-03-30
Figures 1-14. The flow scheme for this Case 2 is the same as illustrated in
Figure 16 /
Table 3. For this case, the deoiled water was again divided between the HT EC
plus
filtration and an existing water treatment unit without HT EC, solids
dewatering,
solids-water separation, microfiltration, WAC, and a deaerator,
debottlenecking an
existing facility.
[00183] Additional impacts of integrating this FTB-CPF Add-On design on
Base Case
plant operations include: (A) The lime softener throughput rate decreases by
up to
1.4% based on a reduction of up to 11.8% in produced water feed and 40.4%
increase
in the OTSG blowdown recycle rate to the lime softener; (B) The amount of
makeup
water supply to the lime softener increases by 27.6%; (C) The OTSG blowdown to
disposal rate increases by up to 24.1%; (D) The disposal of the blowdown
fraction is
7.5% of total inflows which depending upon the fresh to brackish makeup water
fractions used is between 0.5 and 6.0% below the disposal limit calculated by
the
Alberta Energy Regulator; (E) Additional steam generation capacity will be
required;
(F)Increase in sweet fuel gas supply will be required; and (G) Modifications
or
equipment additions to the oil separation and deoiling trains will be
required.
[00184] The Case 2 conditions and results are shown in Table 5 below.
Table 5.
Reservoir
SOR 3.00
GOR 5.00
Water Losses to Reservoir 12000
(bpd)
Bitumen
bpd 40000
API gravity 7.1
Produced Water from
Reservoir
bpd 108000
TDS (ppm) 1492
TH (ppm) 14
Silica (mg Si02 / 1) 188
48
CA 2962834 2017-03-30
Produced Water Sales (bpd) 300
Produced Gas MMSCFD 0.88
Water from Oil Treating bpd 107700
to FTB add-on 36400
To existing water treatment 71300
Solids from oil treating kg/d 139
Make-up Water
bpd 23100
Si02 (ppm) 7
TDS 7200
TH 200
Water Treatment
Blowdown Recycle (bpd) 13900
Landfill / disposal (bpd) 1000
Boiler Feed Water
bpd 153900
Steam Generation
Wet Steam Quality (%) 78
Wet Steam bpd 153900
HP Steam Quality (%) 100
HP Steam bpd 120000
Blowdown (bpd) 33900
Condensate Recycle (bpd) 9100
Blowdown to Disposal (bpd) 9800
Deaerator steam (bpd) 1100
[00185] FTB-CPF Add-On CASE 2+ - Increase Steam Quantity and Quality
[00186] The FTB-CPF Add-On CASE 2+ design is an extension of FTB-CPF Add-
On
CASE 2 utilizing the design theory applied for FTB-CPF Add-On CASE 1 to
increased steam quality generated by the OTSGs. Similar to FTB-CPF Add-On
CASE 2, a 33% increases in the quantities of BFW, steam to field and oil
production
49
CA 2962834 2017-03-30
over the Base Case design is achieved. The flow scheme for this Case 2+ is the
same
as illustrated in Figure 16 / Table 3.
[00187] Additional impacts of integrating this FTB-CPF Add-On design on
Base Case
plant operations include: (a) The lime softener throughput rate decreases by
up to
6.2% based on a reduction of up to 11.7% in produced water feed a 14.1%
increase in
the OTSG blowdown recycle rate to the lime softener and up to 12.7% increase
in the
required makeup water supply; (b) The OTSG blowdown to disposal rate decreases
by
up to 10%; (c) The disposal of the blowdown fraction is 7.5% of total inflows
which,
depending upon the fresh to brackish makeup water fractions used, is between
3.4 to
8.5% below the disposal limit calculated by the Alberta Energy Regulator; (d)
Additional steam generation capacity will be required; (e) Increase in sweet
fuel gas
supply will be required; (f) Modifications or equipment additions to the oil
separation
and deoiling trains will be required; and (g) The BFW produced by the FTB-CPF
Add-On package is blended with the existing BFW produced by the Base Case
water
treatment processes to achieve a silica reduction of up to 24% and a TOC
reduction of
up to 30% thereby enabling the OTSGs to increase the high pressure steam
quality to
82% while generating the same mass of steam to field using 4.9% less BFW.
[00188] The Case 2+ conditions and results are shown in Table 6 below.
Table 6.
Reservoir
S OR 3.00
GOR 5.00
Water Losses to Reservoir 12000
(bpd)
Bitumen
bpd 40000
API gravity 7.1
Produced Water from
Reservoir
bpd 108000
TDS (ppm) 1492
TH (ppm) 14
CA 2962834 2017-03-30
Silica (mg Si02 /1) 188
Produced Water Sales (bpd) 300
Produced Gas MMSCFD 0.88
Water from Oil Treating bpd 107700
to FTB add-on 36400
To existing water treatment 71300
Solids from oil treating kg/d 139
Make-up Water
bpd 20350
5i02 (ppm) 7
TDS 7200
TH 200
Water Treatment
Blowdown Recycle (bpd) 11300
Landfill / disposal (bpd) 950
Boiler Feed Water
bpd 146300
Steam Generation
Wet Steam Quality (%) 82
Wet Steam bpd 146300
HP Steam Quality (%) 100
HP Steam bpd 120000
Blowdown (bpd) 26300
Condensate Recycle (bpd) 6800
Blowdown to Disposal (bpd) 7100
Deaerator steam (bpd) 1100
[00189] FTB-CPF Add-On CASE 3 - Debottlenecking Steam Generation Capacity
[00190] The FTB-CPF Add-On CASE 3 design incorporates additional OTSG
steam
generation to increase steam to field and oil production by 33% while lowering
the
BFW production and steam to field requirements for Base Case operations by
4.2%
The additional steam generator design used for this case is based on the
complete
51
CA 2962834 2017-03-30
FTB-CPF design that uses Rife Tubes installed in the last 50% of the radiant
tube
section of the OTSG to enable the generator to produce 90% steam quality.
[00191] The Add-On for Case 3 includes the addition of HT EC modules,
solids
dewatering, solids-water separation, microfiltration, WAC, and a deaerator, as
shown
in embodiments of one or more of Figures 1-14. For this case, the deoiled
water was
again divided between the HT EC plus filtration and an existing water
treatment unit
without HT EC, solids dewatering, solids-water separation, microfiltration,
WAC, and
a deaerator, debottlenecking an existing facility. This case also included a
dedicated
boiler feed water tank, with flow divided between an add on with a 90% steam
quality
OTSG with HP separator and an existing steam generation system.
[00192] Additional impacts of integrating the FTB-CPF Add-On CASE 3 design
with
Base Case plant operations include: (a) The lime softener throughput rate
decreases by
up to 5.1% based on a reduction of up to 11.7% in produced water feed, up to
19.2%
increase in the OTSG blowdown recycle rate to the lime softener and up to
16.3%
increase in the required makeup water supply; (b) The OTSG blowdown to
disposal
rate decreases by up to 1.3%; (c) A dedicated BFW storage tank is required for
the
90% OTSG to segregate the higher quality BFW from the traditional Base Case
BFW
that contains a much higher concentration of silica and dissolved TOC; (d)
Increase
in sweet fuel gas supply will be required; and (e) Modifications or equipment
additions to the oil separation and deoiling trains will be required
[00193] A block flow diagram illustrating the Case 3 flow scheme is
provided in
Figure 17. The reference numerals and unit operations used in the Case 3 flow
diagram are provided in Table 7 below.
Table 7. Figure 17 unit operations and reference numbers.
Reservoir 1700 Produced Water 1702
Produced Water to 1704 Water Losses to 1706
Sales Reservoir
FTB Add-on 1708 HT EC 1710
Solids Dewatering 1712 Solids to Landfill 1714
Solids-Water 1716 Microfiltration 1718
Separations
WAC 1720 Deaerator 1722
52
CA 2962834 2017-03-30
Water Treatment 1724 Make-up water 1726
PW Tank 1728 WLS 1730
AF/WAC 1732 Water Treatment 1734
wastes to Landfill
Boiler Feed Water 1736 Boiler Feed Water to 1738
Tank Existing Steam Gen.
Boiler Feed Water to 1739 Deaerated BFW 1741
Add-On Steam Gen.
Additional Steam 1740 HP Steam 1742
Generation
Dedicated BFW Tank 1744 90% OTSG 1746
HP Separations 1748 Blowdown 1750
Existing Steam 1752 OTSG 1754
Generation
HPSeparations 1756 LP Flash 1758
Wet Steam 1760 HP Steam 1762
Blowdown 1764 Blowdown to 1766
Disposal
Deaerator Steam 1768 Blowdown Recycle 1770
[00194] The Case 3
conditions and results are shown in Table 8 below.
Table 8.
Reservoir
SOR 3.00
GOR 5.00
Water Losses to Reservoir 12000
(bpd)
Bitumen
bpd 40000
API gravity 7.1
Produced Water from
Reservoir
53
CA 2962834 2017-03-30
bpd 108000
TDS (ppm) 1492
TH (ppm) 14
Silica (mg Si02 /1) 188
Produced Water Sales (bpd) 300
Produced Gas MMSCFD 0.88
Water from Oil Treating bpd 107700
to FTB add-on 36400
To existing water treatment 71300
Solids from oil treating kg/d 139
Make-up Water
bpd 21050
Si02 (ppm) 7
TDS 7200
TH 200
Water Treatment
Blowdown Recycle (bpd) 11800
Landfill / disposal (bpd) 950
Boiler Feed Water
bpd 148000
To existing steam generation 110500
To add-on steam generation 37500
Steam Generation
Wet Steam Quality (%) 78
Wet Steam bpd 110500
HP Steam Quality (%) 100
HP Steam bpd 86200
Blowdown (bpd) 24300
Condensate Recycle (bpd) 7300
Blowdown to Disposal (bpd) 7800
Deaerator steam (bpd) 1100
54
CA 2962834 2017-03-30
Add-on Steam Generation
Steam Quality (%) 90
HP Steam Quality (%) 100
HP Steam (bpd) 33800
Blowdown (bpd) 3700
[00195] FTB-CPF Add-On CASE 4¨ Fixed Capacity Evaporator / Drum Boiler
[00196] The FTB-CPF Add-On CASE 4 design was developed for a thermal heavy
oil
producer that may encounter a drop in production using their design steam to
oil ratio
of 3Ø The facility included a fixed capacity front end mechanical vapor
(MVC)
evaporator to produce very high quality BFW from produced water which allowed
for
drum boilers to be used to generate high pressure steam. Due to the fixed
capacity of
the MVC evaporator the plant would not be able to increase BFW production and
produce the additional steam necessary with a new drum boiler to satisfy a new
higher
steam to oil ratio target of 4.5 to maintain the 30,000 bopd production
capacity.
[00197] The FTB-CPF Add-On Case 4 design developed incorporated a dual EC
module FTB water treatment package to produce a BFW for operating a Rifle Tube
OTSG to produce 90% quality steam which, after high pressure separation, added
37.6% more 100% quality steam to field. The main advantage provided by this
design
is up to a 7,500 bopd increase in oil production to 27,500 bopd which is 8.3%
below
the design production capacity for the facility. Achieving the design oil
production
target or increasing oil production is possible by reducing the size of the
water
treatment module and operating more than one train and if necessary installing
a
larger OTSG or two smaller ones.
[00198] Additional impacts of integrating the FTB-CPF Add-On CASE 4 design
within a facility equipped with MVC evaporators and drum boilers included: (a)
Sustained operation of the MVC evaporator at design capacity with no changes
in
Drum Boiler steam to field generated; (b) Generation of 2650 bopd of blowdown
from
the 90% OTSG for blending with the 4800 bopd of blowdown from the evaporator
prior to disposal thereby not changing the disposal well license
specifications; (c)
Increase in sweet fuel gas supply will be required; (d) Increasing production
and
lower disposal volumes are possible using a larger sized FTB-Add-On design and
CA 2962834 2017-03-30
multiple OTSGs. This enhanced design will process additional produced water
for
BFW supplied to the OTSGs and back off the amount of produce water processed
by
the existing Evaporator and replace that produced water with an equivalent
volume of
blowdown from the OTSGs. This maintains evaporator BFW production capacity and
will reduce blowdown waste water disposal volume by up to 50%.
[00199] A block flow diagram illustrating the Case 4 flow scheme is
provided in
Figure 18. The reference numerals and unit operations used in the Case 4 flow
diagram are provided in Table 9 below.
Table 9. Figure 18 unit operations and reference numbers.
Reservoir 1800 Produced Water 1802
Produced Water to 1804 Water Losses to 1806
Sales Reservoir
Deoiling 1808 Skim Tank 1810
IGS/ISF/ORG units 1812 Deoiled Water 1814
Existing Boiler 1816 Make-Up Water 1818
System
Deaerator 1820 Evaporator 1822
BFW Tank 1824 Drum Boiler 1826
HP Steam 1828 Blowdown Recycle 1830
to Evaporator
Evaporator 1832 FTB Add-on 1834
Blowdown
HT EC 1836 Solids Dewatering 1838
Solids-Water 1840 Micro Filtration 1842
Separations
WAC / SAC 1844 Deaerator 1846
Add-On Steam Gen 1848 Dedicated BFW tank 1850
90% SQ OTSG 1852 HP Separations 1854
LP Flash 1856 Boiler Feed Water 1858
HP Steam 1860 Deaerator Steam 1862
Blowdown to 1864 Solids to Landfill 1866
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Disposal
[00200] The Case 4 conditions and results are shown in Table 10 below.
Table 10.
Reservoir
S OR 3.00
GOR 5.00
Water Losses to Reservoir 12000
(bpd)
Bitumen
bpd 40000
API gravity 7.1
Produced Water from
Reservoir
bpd 111400
TDS (ppm) 1492
TH (ppm) 14
Silica (mg 5i02 /1) 188
Produced Water Sales (bpd) 300
Produced Gas MMSCFD 0.88
Water from Oil Treating bpd 111100
to FTB add-on 36400
To existing water treatment 74700
Solids from oil treating kg/d 130
Make-up Water
bpd 21900
SiO2 (ppm) 7
TDS 7200
TH 200
Water Treatment
Blowdown Recycle to 1800
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evaporator (bpd)
Landfill / disposal (bpd) 4800
Boiler Feed Water
bpd 148000
To existing drum boiler 74700
To add-on EC / Filtration and 36400
steam generation
Drum Boiler Steam
Generation
HP Steam Quality (%) 100
HP Steam bpd 90000
Boiler Blowdown Recycle 1800
(bpd)
Evaporator Blowdown to 4800
Disposal (bpd)
Add-on Steam Generation
Steam Quality (%) 90
HP Steam Quality (%) 100
HP Steam (bpd) 33800
Blowdown (bpd) 2650
Deaerator steam (bpd) 1100
Total Disposal bpd 7450
[00201] FTB-CPF Add-On CASE 5 ¨ Small Facility Ion Exchange ¨ OTSG
[00202] The FTB-CPF Add-On CASE 5 design was developed for a small 6,000
bopd
thermal heavy oil producer that may be treating a blend of fresh and brackish
water
with ion exchangers to make BFW to operate OTSGs at 90% SQ. All of the
produced
water recovered from the field was deoiled and being disposed of as allowed by
the
Alberta Energy Regulator (AER). Due to, for example, limitations in the
groundwater
AER license the company is required to treat the deoiled produced water for
OTSG
operation to increase steam to field and oil production.
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CA 2962834 2017-03-30
[00203] The FTB-CPF Add-On Case 5 design developed for such a producer
incorporated a single EC module FTB water treatment package to produce a BFW
for
operating a Rifle Tube OTSG to produce 90% quality steam which, after high
pressure separation, added 83.3% more 100% quality steam to field. The main
advantage provided by this design is a 5,000 bopd increase in oil production
using
their steam to oil ratio of 2.5. Additional impacts of integrating the FTB-CPF
Add-On
CASE 5 design within a facility equipped with ion exchangers only and OTSGs
include: a 1000 bopd (59%) increase in OTSG blowdown sent to disposal; a 17%
reduction in the bopd of produced water sent to disposal; no change in the
amount of
groundwater withdrawn or the withdrawal license is required; increase in sweet
fuel
gas supply will be required; and modifications or equipment additions to the
oil
separation and deoiling trains will be required.
[00204] A block flow diagram illustrating the Case 5 flow scheme is
provided in
Figure 19. The reference numerals and unit operations used in the Case 5 flow
diagram are provided in Table 11 below.
Table 11. Figure 19 unit operations and reference numbers.
Reservoir 1900 Produced Water 1902
Produced Water to 1904 Water Losses To 1906
Sales Reservoir
Deoiling 1908 Skim Tank 1910
Secondary Deoiling 1912 HP Steam 1914
Deoiled Water to 1916 Deoiled water to FTB 1918
disposal Add-on
Make-up water 1920 Ion exchangers 1922
Regen waste to 1924 BFW tank 1926
disposal
OTSG 1928 Blowdown 1930
FTB add-on 1932 HTEC 1934
Solids Dewatering 1936 Landfill Solids 1938
Solids-Water 1940 MicroFiltration 1942
Separations
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WAC / SAC 1944 Deaerator 1946
Steam Gen Add-on 1948 Dedicated BFW Tank 1950
90% SQ OTSG 1952 HP Separations 1954
LP Flash 1956 Boiler Feed Water 1958
Wet Steam 1960 HP Steam 1962
Deaerator Steam 1964 Blowdown 1966
[00205] The Case 5 conditions and results are shown in Table 12 below.
Table 12.
Reservoir
SOR 2.50
GOR 5.00
Water Losses to Reservoir 2750
(bpd)
Bitumen
bpd 11000
API gravity 8
Produced Water from
Reservoir
bpd 24750
TDS (ppm) 5500
TH (ppm) 300
Silica (mg Si02 /1) 150
Produced Water Sales (bpd) 50
Produced Gas MMSCFD 0.88
Water from Oil Treating bpd 13500
to FTB add-on 13500
To existing water treatment 0
Solids from treating kg/d 53
Make-up Water bpd 18700
To existing ion exchange and
CA 2962834 2017-03-30
OTSG
Make-up Water Treatment Landfill / disposal (bpd) 2000
Existing OTSG
Steam bpd 16700
Steam Quality 90%
Steam to Field (bpd) 15000
Blowdown to disposal (bpd) 1700
Add-on Steam Generation
Steam Quality (%) 90
HP Steam Quality (%) 100
HP Steam (bpd) 12500
Blowdown (bpd) 1000
Deaerator steam (bpd) 400
Total Blowdown to Disposal bpd 2700
[00206] While the disclosure includes a limited number of embodiments,
those skilled
in the art, having benefit of this disclosure, will appreciate that other
embodiments
may be devised which do not depart from the scope of the present disclosure.
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