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Cenovus FCCL Ltd. 7-1 Facilities

CLTP – Phase H and Eastern Expansion March 2013

Volume 1, Section 7

7 FACILITIES

7.1 OVERVIEW

This section describes the facilities being added and the

associated operations modified as part of the Project. The

Phase H as well as field and support facilities are described in

this section. The majority of the figures and drawings associated

with this section have been provided in Volume 1C.

7.2 CENTRAL PROCESSING FACILITY OVERVIEW

The currently approved CLTP CPF is proposed to be expanded to

increase production capacity. This single-phase expansion is

referred to as Phase H (or Phase 1H in facility drawings). The

steam and bitumen capacities for all phases of the CPF are

summarized in Table 7.2-1.

Table 7.2-1 Steam Capacity and Bitumen Production Capacity

Phase Status

Dry Steam

Capacity

BitumenProductionCapacity

m

3

/d ColdWaterEquivalent(CWE) (a)

[bbl/d] [m3/d](a)

Phases A and B Operating 5,347 18,800 2,989

Phase C Operating 11,392 40,000 6,359

Phase D Operating 11,392 40,000 6,359

Phase E Approved 11,392 40,000 6,359

Phase F Approved 14,453 50,000 7,949

Phase G Approved 14,512 50,000 7,949

Phases A to G (Sub-total) See Above 68,489 238,800 37,964

CDE 2nd Stage OTSGsApplicationSubmitted

6,695 21,200 3,371

Phases A to G, includes CDE 2nd

Stage OTSGs (Sub-total)

See Above 75,184 260,000 41,335

Phase H (the Project) Proposed 14,512 50,000 7,949

Phases A to G, includes CDE 2nd Stage OTSGs and the Project(Total)

See Above 89,696 310,000 49,284

(a) Totals may not add due to rounding.

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Volume 1, Section 7

A summary of the Project equipment and the associated

subsections in which equipment is referenced is provided in

Table 7.2-2. Equipment lists are also provided in

Appendix 1-VII.

7.2.1 Steam Generation

Five OTSGs will be installed to provide Phase H steam capacity.

The placement of these OTSGs within the CPF plot plan is shown

in Figure 7.2-1. The CPF will have a fixed maximum steam rate

based on the number of steam generators available, while the

bitumen production rate will depend on the Steam to Oil Ratio

(SOR) achieved. The average assumed SOR for Phases A to H is

1.78.

The dry steam rates for Phases C to E are based on a steam

quality of 77%. The steam quality for Phases F to H has been

upgraded to 80% based on CPF performance to date. As per

previous amendments, emission modelling for all steam

generators is based on the burner limitations which equates to a

steam rate of approximately 12,918 m³/d (CWE) for each of

Phases C to E, and a rate of 16,148 m³/d (CWE) for each of

Phases F to H. For Phases G and H in particular emissions

modelling is based on operation of five 1st stage OTSGs at

higher firing. Operation of the OTSG as a 2nd stage OTSG is

expected to have the same or lower emissions than as a 1st

stage OTSG assuming that the 2nd stage OTSG may operate at

a lower steam quality. This relative conservatism in emission

modelling ensures the approved emissions rates and modeled

impacts provide margin for ongoing optimization efforts. The

CPF may be debottlenecked in the future, as required, to ensure

the production treating, heat exchange and water treatment

system capacities match the proven steam capacity.

Overall CPF block flow diagrams for a produced water to steamratio (PWSR) of 1.0, an overall energy balance, development

profile with ERCB water usage formulas, and a simplified water

balance are included in Appendix 1-VIII.

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Volume 1, Section 7

Table 7.2-2 Central Processing Facility Equipment for the Project

Equipment DescriptionEquipment Identification

NumberSub-SectionReference

Associated

Process FlowDiagrams(a)

Inlet Degasser V-4615

7.4.1

(ProductionProcessing)

CL1H-42-PFD-04-160-01

CL1H-42-PFD-

04-162-01

Emulsion/Boiler FeedWater (BFW) Exchangers

E-4640 A-D

Free Water Knock-Out(FWKO) Drum

V-4600

Treaters V-4620/4660

Sales Oil/BFWExchangers

E-4630A/B, E-4670A/B

Sales Oil/GlycolExchangers

E-4635A/B, E-4675A/B

Produced Water/BFW

Exchangers E-4645A-FProduced Water/Glycol

ExchangersE-4650A-E

Demulsifier InjectionPackage

PK-4653, T-4651

Clarifier InjectionPackage

PK-4657, T-4655

Oil Slops Cooler E-4680

Desand Jet Water Pump P-46447.4.2 (DesandingSystem)

CL1H-42-PFD-04-143-01

Glycol Heater H-7300C7.5.3

(CPF Glycol System)

CL1H-42-PFD-07-142-01

CL1H-42-PFD-07-142-02

Glycol Circulation Pumps P-7330 F/G

Glycol Air Coolers AC-7350 S-Z

Brackish Water BoosterPumps

P-0902F/G 7.6.2

(Make-up WaterTreatment System)

CL1H-42-PFD-01-140-01

CL1H-42-PFD-01-146-02

Sodium HypochloritePumps

P-0905D

Skim Tank T-0522

7.6.2.1

(Produced WaterDeoiling System)

CL1H-42-PFD-

01-161-01CL1H-42-PFD-01-166-02

Induced Gas Flotation(IGF) Vessel

V-0525

IGF Package PK-0525

IGF Oil Pumps P-0533A/B

IGF Oil Filters F-0523A-H

Oil Removal Filter (ORF)

Feed Pumps P-0535A/B

Oil Removal FilterPackages (ORFs)

PK-0540A/B/C

Deoiled Water Tank T-0555

Deoiled Water Pumps P-0558A/B/C

Oil Recycle Tank T-0545

Oil Recycle Pumps P-0548A/B

Water Recycle Pumps P-0550A/B

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Table 7.2-2 CPF Equipment for the Project (continued)

Volume 1, Section 7

Equipment Description Equipment IdentificationNumber Sub-SectionReference

Associated


Deoiling PolymerInjection Package

PK-0687, T-0685

Warm Lime Softener T-0560

7.6.2.2

(Water SofteningSystem)

CL1H-42-PFD-01-162-01

CL1H-42-PFD-01-163-01

CL1H-42-PFD-01-164-01

CL1H-42-PFD-01-166-01

Clear Well T-0570

Direct Steam InjectionHeater

X-0559

Sludge Recycle Pumps P-0568A/B

Sludge Blowdown Pumps P-0697A/B

Sludge Centrifuge C-0695

Centrate Sump Z-0690

Centrate Pumps P-0690A/B

Lime Slurry Pumps P-0756A/B

Lime Storage and FeedPackage

PK-0750

Magox Storage and FeedPackage

T-0760

Magox Slurry Pump P-0766

After-Filter Feed Pumps P-0575A/B/C

Warm Lime Softener

(WLS) After-Filters

Packages

PK-0580A-D

Suspended Solids Filters F-0600A-M, F-0605A-M, F-0610A-M

Primary Strong AcidCation (SAC) Softeners

V-0620A-F

Polisher Weak AcidCation (WAC) Softeners

V-0630A-D

Produced Water BrineSaturator

T-0655

7.6.3.2

(Water SofteningSystem)

CL1H-42-PFD-01-162-01

CL1H-42-PFD-01-163-01

CL1H-42-PFD-01-164-01

CL1H-42-PFD-01-166-01

Brine Pumps P-0657A/B

Acid Storage Tank T-0660 Acid Fume Scrubber V-0666

Acid Regeneration Pump P-0664

Caustic Storage Tank T-0670

Caustic RegenerationPump

P-0674

Neutralization Tank T-0680

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Table 7.2-2 CPF Equipment for the Project (continued)

Volume 1, Section 7

Equipment Description Equipment IdentificationNumber Sub-SectionReference

Associated


2nd Stage SteamSeparator

V-2885

7.9

(Steam Generation)

CL1H-42-PFD-02-140-01

CL1H-42-PFD-02-142-01

CL1H-42-PFD-02-161-01

CL1H-42-PFD-02-162-01

BFW / BlowdownExchangers

E-3065 A/B

Blowdown/GlycolExchanger

E-3075

2nd Stage BFW ChargePumps

P-2880 A/B

2nd Stage BFW /Blowdown Exchanger

E-2890

Boiler Feed Water (BFW)Booster Pumps

P-3010 F/G

Boiler Feed Water (BFW)Charge Pumps

P-3015 F/G

Sulphite Injection Pump P-3087C

Chelant Injection Pump P3089C

Filming Amine ChemicalPackage

PK-3081, T-3080

Skim Tank T-0522

7.10

(Vapour RecoverySystem)

CL1H-42-PFD-07-140-01

CL1H-42-PFD-07-140-02

Induced Gas Flotation(IGF) Vessel

V-0525


Deoiled Water Tank V-0555

Warm Lime Softener(WLS)

T-0560

Clear Well T-0570

Vapour Recovery Unit(VRU) CompressorPackage

PK-7615

(a) Diagrams provided in Appendix 1-IX.

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Volume 1, Section 7

7.2.2 Make-Up Water Treatment

Phase H accommodates make-up water requirements with BasalMcMurray water, the same configuration as Phases F and G.

Since separate treatment of this high hardness water would

result in prohibitive regenerations, an integrated treatment of

brackish and produced water was selected. The cold brackish

water will be introduced upstream of the WLS, and a direct

steam injection heater will be used to maintain a uniform inlet

temperature. Brackish water heat integration was excluded from

the design to prevent hardness precipitation as the water is

heated. An external cooling system will provide cooling for seal

flush, dilution water and process coolers which were previously

in cold softened brackish water service. This external coolingsystem will mitigate potential for the brackish water make-up to

limit operational flexibility at high PWSRs when the required

brackish water make-up demand may be lower.

7.2.3 Water Re-Use and Disposal

Water recycle will be maximized by using high steam quality

and maximum blowdown recycle. The flexibility to transfer one

of the Phase H OTSGs into blowdown boiler (2nd stage OTSG)

service is part of the design. Refer to Figure 7.2-2 for a sketch

of the 2nd stage OTSG operation. The ability to recycle

blowdown to the deoiled water tank and BFW tank is also part of

the design. Flexibility to use either blowdown recycle or a 2nd

stage OTSG will allow Phase H to optimize operation based on

PWSRs and water chemistry. Optimized operations will promote

water reuse, minimize blowdown disposal, and reduce make-up

water.

Development profiles indicating anticipated production and

water usage are included in Appendix 1-VIII. In these models it

is assumed that all steam generators will operate at 80% steamquality. The PWSR equal to 1.0 cases yield the maximum make-

up water requirements. The predicted high PWSR cases yield the

maximum blowdown disposal requirements.

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Volume 1, Section 7

7.2.4 Produced Gas Treatment

Produced gas from wells will be treated and used as fuel gas inthe OTSGs. The produced gas contains hydrogen sulphide (H2S)

and requires sulphur recovery to reduce the H2S content before

combustion. Refer to Section 7.11 for further details on H2S

recovery.

7.2.5 Bitumen Production Treating

The bitumen is blended with diluent to facilitate treating.

Additional diluent is added to the sales oil product to meet

pipeline product viscosity and density specifications.

Heat and material balances are included in Appendix 1-X.

7.3 FLOW RATES

The anticipated cumulative flow rates for the expanded CPF are

listed in Table 7.3-1.

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Volume 1, Section 7

Table 7.3-1 CPF Cumulative Flow Rates

Parameter Units Phases A to H

Saturated steam from steam

generators[m³/d CWE] 89,696 (a)

Saturated steam to injection wells [m3 /d CWE] 88,936 (a)

Oil from production wells [Sm3 /d] 49,283 (a)

Produced water from wells [m3 /d CWE] 88,936 (a)

Produced gas from wells (dry basis) [e³Sm3 /d] 824.6 (a)

Lift gas [e3Sm3 /d] 282.5 (a)

Fresh water consumption [Sm3 /d] 229 (a)

Brackish make-up water consumption [Sm3 /d]9,426 (a)

23,650 (Upset)(b)

Steam blowdown to disposal [Sm

3

/d]

8,293 (a)

22,247 (Upset)(b) Regeneration/neutralization waste todisposal(c)

[Sm3 /d]734 (a)

1,042 (Upset)(b)

(a) Refer to the Block Flow Diagrams and Simplified Water Balances in Appendix 1-VIII.(b) Upset conditions indicated are based on a blowdown recycle rate of 0% and a PWSR of 1.0. For

simplicity, it is assumed that all OTSGs operate at a steam quality of 80% in the upset case. Notethat the Block Flow Diagrams and Simplified Water Balances (Appendix 1-VIII) assume an 80% steamquality for all the OTSGs, except the Phase CDE 2nd Stage OTSGs, which use a steam quality of 75%.

(c) Regen waste quantities are based on assumed water quality. Design assumes 20 ppm total hardnessas CaCO3 for the produced water, 140 ppm as CaCO3 for the Clearwater B (Phases A to E) and 352ppm as CaCO3 for the Basal McMurray (Phases F to H). Operating capacities for the Strong AcidCation (SAC) and Weak Acid Cation (WAC) resins are based on vendor recommendations. Blowdown

recycle and TDS influence sodium interference and reduce the operating capacity of SAC resin. Thismay contribute to more frequent regenerations and result in increased regeneration waste. Use of

higher hardness water will similarly require more frequent regeneration and result in increasedregeneration waste.

7.3.1 Bitumen Rates

Bitumen production rates are presented in Table 7.3-2.

Table 7.3-2 Bitumen Production Capacity

Phase(s)Bitumen Production Capacity(a)

[bbl/d] [m3/d]

A to E 138,800 22,067CDE 2nd Stage OTSGs 21,200 3,371

F and G 100,000 15,898

H (The Project) 50,000 7,949

A to H 310,000 49,284

(a) Totals may not add due to rounding.

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Volume 1, Section 7

7.3.2 Water Rates

Development profiles indicating anticipated production andwater usage are included in Appendix 1-VIII.

For the three cases provided in this section it is assumed that all

steam generators will operate at 80% steam quality. This

assumption was made to simplify the model and may be slightly

different than the block flow diagram numbers in

Appendix 1-VIII, which use 80% steam quality for Phases A to

H, and 75% for the CDE 2nd Stage OTSGs.

The ideal blowdown recycle case is based on a PWSR equal to

1.0 (Table 7.3-3).

The maximum make-up water requirement is based on a PWSR

equal to 1.0 with 0% blowdown recycle (Table 7.3-4).

The maximum disposal requirement is based on a PWSR equal

to 1.27 (Table 7.3-5). This is the highest expected PWSR as per

the development profile in Appendix 1-VIII.

Under normal operating conditions the make-up water and

disposal rates should range between the maximums listed inTables 7.3-4 and 7.3-5.

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Volume 1, Section 7

Table 7.3-3 Water Balance Summary, Ideal Blowdown Recycle Case

Phase(s) PWSR

Steam

Quality

Blowdown

Recycle

Brackish

Make-up

Water Treating

Regen Loss

WLS Sludge

Water

Blowdown

Disposal

[%] [%] [tonnes/day] [tonnes/day] [tonnes/day] [tonnes/day]

A to E 1.00 80 50 5,624 586 31 4,898

A to E, plus CDE2nd Stage OTSGs

1.00 80 75 3,096 518 35 2,412

F and G 1.00 80 50 3,809 130 26 3,539

H 1.00 80 50 1,908 65 13 1,773

A-H 1.00 80 63 8,813 714 74 7,723

Table 7.3-4 Water Balance Summary, Maximum Make-Up Water Case

Phase(s) PWSR

Steam

Quality

Blowdown

Recycle

Brackish

Make-up

Water Treating

Regen Loss

WLS Sludge

Water

Blowdown

Disposal

[%] [%] [tonnes/day] [tonnes/day] [tonnes/day] [tonnes/day]

A to E 1.00 80 0 10,715 730 29 9,839

A to E, plus CDE

2nd Stage OTSGs1.00 80 0 12,593 825 35 11,624

F and G 1.00 80 0 7,371 145 31 7,082H 1.00 80 0 3,686 72 16 3,541

A-H 1.00 80 0 23,650 1,042 82 22,247

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Volume 1, Section 7

Table 7.3-5 Water Balance Summary, Maximum Disposal Case

Phase(s) PWSR

Steam

Quality

Blowdown

Recycle

Brackish

Make-up

Water

Treating

Regen Loss

WLS Sludge

Water

Blowdown

Disposal

ProducedWater

Disposal

[%] [%] [tonnes/day] [tonnes/day] [tonnes/day] [tonnes/day] [tonnes/day]

A to E 1.27 80 0 2,733 498 37 9,839 2,898A to E, plus CDE 2nd

Stage OTSGs1.27 80 0 2,850 551 44 11,624 3,105

F and G 1.27 80 0 0 145 27 7,082 313

H 1.27 80 0 0 72 13 3,541 156

A-H 1.27 80 0 2,850 767 84 22,247 3,574

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Volume 1, Section 7

7.3.3 Produced Water Rates

The produced water flow rates are presented in Table 7.3-6.

Table 7.3-6 Produced Water Rates

Phase(s)Produced Water Rates

[Sm3/d]

A to E 39,524

CDE 2nd Stage OTSGs 6,695

F and G 28,459

H 14,259

A to H 88,936

These design values are based on a PWSR equal to 1.0. Higher

water rates may occur as a result of PWSR greater than one or

optimization of steam rates.

7.3.4 Produced Gas Rates

Based on operating data, a Gas to Oil Ratio (GOR) of 11 Sm3 of

dry produced gas per m3 of bitumen is assumed. Produced gas

flow rates are provided in Table 7.3-7.

Table 7.3-7 Produced Gas Rates

Phase(s)Produced Gas Rates

[e3Sm3/d]

A to E 242.7

CDE 2nd Stage OTSGs 37.1

F and G 174.9

H 87.4

A to H 542.1

7.3.5 Lift Gas Rates

The CLTP utilizes gas lift and ESPs for SAGD production; refer to

Section 5 for modes of well operation. Gas lift will be used for

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Volume 1, Section 7

several months after start-up of SAGD well pair operations

before conversion to ESP operation. The total lift gas is not

additive between phases as more mature wells will be converted

to ESP operation prior to start-up of new gas lift wells. Fordesign purposes a maximum lift gas rate of 282.5 e3Sm3 /d was

used based on assuming a maximum of 56 wells on lift gas at

any given time.

7.4 CENTRAL PROCESSING FACILITY PRODUCTIONDESCRIPTION

7.4.1 Production Processing

The production processing design for Phase H is very similar to

the approved Phase G design.

Reference Process Flow Diagrams (PFDs) for all Phases are

included in Appendix 1-IX. Phase H production treating is

depicted on the following drawings:

• CL1H-42-PFD-04-140-01;

• CL1H-42-PFD-04-141-01;

• CL1H-42-PFD-04-160-01;

• CL1H-42-PFD-04-162-01; and

• CL1H-42-PFD-06-140-01.

Produced emulsion (bitumen and produced water) and the

associated produced gas are piped from the well pads to the CPF

in a common pipeline. The produced emulsion is degassed and

routed to production treating. Separated gas is routed to the

produced gas system.

The casing gas pipeline (which contains produced gas from the

well casing as well as separated lift gas lift when applicable),

connects to the CPF separately and bypasses inlet degassing.

This stream is sent first to a casing gas slug catcher for liquids

removal. The separated gas is mixed with gas from inlet

emulsion degassing then routed to an aerial cooler to condense

residual steam and condensable light hydrocarbons. The

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Volume 1, Section 7

condensed liquids are separated from the non-condensable

produced gas in the three-phase produced gas separator.

Condensed water is recycled to the skim tanks and condensed

hydrocarbon liquids are recovered into the slop system. Thecooled produced gas is sent to the scavenger unit for treating.

Treated gas is mixed with sweet fuel gas make-up and used as

fuel in the OTSGs.

Emulsion from inlet degassing is cooled to the desired treating

temperature through the emulsion/BFW heat exchangers. The

cooled emulsion is then distributed to an emulsion treating train

consisting of a FWKO followed by two treaters operating in

parallel.

Diluent must be added to the emulsion to reduce viscosity and

density. Before diluent is added, the bitumen will typically be

heavier than water, or neutrally buoyant. Blending diluent with

the produced emulsion allows conventional oil/water separation

technologies to be used. The piping from the diluent pumps is

configured to allow controlled diluent flow to any of the following

mixing points to optimize exchanger and oil treating

performance:

• upstream of the emulsion/BFW exchangers;

• upstream of the FWKO;

• upstream of the treaters;

• sales oil to Lease Automated Custody Transfer (LACT);and

• any combination of these locations.

The oil product leaving the treaters is cooled to 50°C in the

sales oil heat exchange train before being stored in the sales oil

tanks.

Sales oil has a maximum allowable Basic Sediment and Water

(BS&W) of 0.5% by volume. If the product from a treater

exceeds the sales oil specification (off-spec), it is automatically

diverted to an off-spec tank. Off-spec oil can be recycled back

into the oil treating train, sent to the flash treating system, or

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Volume 1, Section 7

blended with sales oil that meets sales oil specification as

conditions allow.

Sales oil meeting specifications is pumped to the LACT unit for

shipping to market. Upstream of the LACT unit, additional

diluent can be added to the oil to meet the shipping density and

viscosity specifications on an as required basis.

Produced water from the FWKOs and treaters is cooled to 90°C

in the produced water/BFW and produced water/glycol

exchangers and then routed to the skim tanks.

Production processing equipment required for Phase H is listed

in Table 7.4-1.

Table 7.4-1 Phase H Production Processing Equipment

Equipment DescriptionEquipment

Identification Number

Inlet Degasser V-4615

Emulsion/Boiler Feed Water (BFW) Exchangers E-4640 A-D

Casing Gas Slug Catcher (a)

Produced Gas Separator (a)

Produced Liquid Coolers (a)

Inlet Vapour Air Coolers (a)

Free Water Knock-Out (FWKO) Drum V-4600

Treaters V-4620/4660

Sales Oil/BFW ExchangersE-4630A/B,E-4670A/B

Sales Oil/Glycol ExchangersE-4635A/B,E-4675A/B

Produced Water/BFW Exchangers E-4645A-F

Produced Water/Glycol Exchangers E-4650A-E

Demulsifier Injection Package PK-4653, T-4651

Clarifier Injection Package PK-4657, T-4655

Oil Slops Cooler E-4680

(a) Equipment is part of the Phase F and is already approved.

7.4.2 Desanding System

The Phase H desanding system is shared with the Phases F and

G desanding systems.

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Volume 1, Section 7

Reference PFDs are found in Appendix 1-IX:

• CL1H-42-PFD-04-143-01.

Over time, sand and sludge will accumulate in the bottom of the

inlet degasser, FWKO drums and treaters. This sludge must be

periodically removed from the bottom of each vessel to avoid

operability and corrosion problems. The vessels are equipped

with internal jetting nozzles and desand slurry drain nozzles.

Clean water from the deoiled water tanks is pumped to the

desand jets inside the vessels using the desand jet water pumps

to help fluidize the bed of sludge. The fluidized slurry is then

cooled by injection of cold brackish water before being flushed

into the desand tank. One additional desand jet water pump is

added in each expansion phase.

After the solids settle out of the slurry in the desand tank, the

decanted liquids are pumped to the slop tanks or to the skim

tanks using the desand tank decant pumps. Any vapours from

the desand tank are collected and sent to the VRU.

Desanding system equipment required for the Project is listed in

Table 7.4-2.

Table 7.4-2 Phase H Desanding System Equipment



Desand Jet Water Pump P-4644

Desand Tank (a)

Desand Tank Decant Pumps (a)


7.5 HEAT RECOVERY INTEGRATION

Equivalent to Phases F and G, heat recovery integration in the

Phase H is driven by the combined treating of brackish and

produced water and uses external cooling as per Section 7.2.2.

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Volume 1, Section 7


• CL1H-42-PFD-02-140-01;

• CL1H-42-PFD-02-161-01;

• CL1H-42-PFD-04-160-01;

• CL1H-42-PFD-05-140-01; and

• CL1H-42-PFD-06-140-01.

7.5.1 Boiler Feed Water Heating

Transferring heat from the production fluids to the boiler feed

water decreases the amount of fuel gas required by the OTSGs.It also decreases the amount of glycol trim cooling required for

the production fluids. Conserving heat reduces the overall

operating costs and emissions of the CPF.


• CL1H-42-PFD-02-140-01; and

• CL1H-42-PFD-02-141-01.

7.5.2 Diluent Heating

The blend diluent cannot be heated without negatively impacting

the sales blend vapour pressure and limited heat recovery is

anticipated by exchanging the treating diluent with the sales oil.

Therefore diluent heat recovery integration has been excluded

to simplify the process.

7.5.3 Glycol System

The Phase H glycol system is an expansion of the Phases F andG glycol system. The Project requires additional glycol heating

and cooling capacity to accommodate increased heat loads.


• CL1H-42-PFD-07-142-01;

• CL1H-42-PFD-07-142-02.

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Volume 1, Section 7

A 60/40% (by weight) solution of tri-ethylene glycol/water is

used as a heat transfer media for both process cooling and

utility heating loads for the following:

• process heat exchangers (sales oil cooling, producedwater cooling, flash treater package cooling, steamblowdown cooling, flare knock-out drum liquids cooling,process make-up water cooling, fuel gas heating, slop oilheating);

• building heaters;

• tank heaters;

• heat tracing;

• combustion air heaters; and

• air make-up units.

During normal operation, recovered process heat will meet the

utility heating demands. Natural gas-fired glycol heaters have

been installed to protect the CPF from freeze-up during a

production turndown or shutdown in the winter.

Hot glycol from the blowdown/glycol exchangers flows through

the combustion air preheaters and the glycol heaters which

operate in parallel. The controls are set up to send hot glycolpreferentially to the glycol heaters (which feed the critical

users), with the remaining hot glycol being sent to the OTSG

combustion air pre-heaters for heat integration. The burner in

the glycol heater will only fire if the glycol temperature drops

below 95°C.

The Phase H critical heating glycol users include:

• building unit heaters;

• tank heating and air cooler winterization coils; and

• pipe and equipment heat tracing.

The combined return stream is then routed to the glycol

expansion drum and glycol circulation pumps. The glycol is

cooled to 45°C (or less in winter operation) before it is

distributed to the glycol-cooled exchangers. The forced-draft

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Volume 1, Section 7

aerial glycol coolers are used to dissipate unrecoverable low

level surplus heat.

A slipstream of glycol from the discharge side of the circulation

pumps is passed through a particulate filter and routed back to

the expansion drum.

Glycol system equipment required for the Project is listed in

Table 7.5-1.

Table 7.5-1 Phase H Glycol System Equipment


Number

Glycol Heater H-7300C

Glycol Circulation Pumps P-7330 F/G

Glycol Air Coolers AC-7350 S-Z

Glycol Storage Tank (a)

Glycol Expansion Drum (a)

Glycol Fill Pump (a)

Glycol Filters (a)


7.6 MAKE-UP WATER AND PRODUCED WATER TREATMENT

7.6.1 Make-Up Water Treatment System

Phase H will accommodate 100% Basal McMurray make-up

water. Untreated brackish water blended with the produced

water upstream of the water treating train will be treated in a

common system. Water treating will consist of warm lime

softening for silica removal and ion exchange for hardness

removal. The Phase H ion exchange will be Strong Acid Cation /Weak Acid Cation (SAC/WAC) with internal regeneration.

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Volume 1, Section 7


• CL1H-42-PFD-01-140-01; and

• CL1H-42-PFD-01-146-02.

Boiler feed water make-up (brackish water) is required to offset

losses associated with the boiler blowdown disposal and water

treatment regeneration waste streams. The make-up water

treatment system is designed to satisfy requirements assuming

no boiler blowdown recycle. Blowdown recycle will be

maximized; however short-term reductions in blowdown recycle

may occur intermittently during upset or start-up scenarios.

Brackish water is defined as groundwater with a Total Dissolved

Solids (TDS) content greater than 4,000 ppm. Brackish water

will be used preferentially for make-up water. Brackish water is

pumped from brackish water wells to the brackish water tanks.

The associated gas from the water is released in the tank and

sent to the CPF fuel gas system. The brackish water is pumped

upstream of the WLS for common treating with the produced

water.

Brackish water system equipment required for the Project is

listed in Table 7.6-1.

Table 7.6-1 Phase H Brackish Water Make-Up Water Treatment System

Equipment

Equipment Description Equipment Identification Number

Raw Brackish Water Tank Note 1

Brackish Water Booster Pumps P-0902F/G

Sodium Hypochlorite Tank (a)

Sodium Hypochlorite Pumps P-0905D


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Volume 1, Section 7

7.6.2 Produced Water Treatment

Phase H produced water treatment will employ a WLS followed

by a SAC/WAC configuration with internal regeneration. The

process includes a caustic wash to wash oil from the SAC resin,

if required, making SAC a viable technology for this service.

Reference PFDs for Phase H are found in Appendix 1-IX:

• CL1H-42-PFD-01-141-01;

• CL1H-42-PFD-01-145-01;

• CL1H-42-PFD-01-161-01;

• CL1H-42-PFD-01-162-01;• CL1H-42-PFD-01-163-01;

• CL1H-42-PFD-01-164-01;

• CL1H-42-PFD-01-166-01; and

• CL1H-42-PFD-01-166-02.

Produced water is treated for reuse as boiler feed water. Oil is

first removed in several stages, followed by softening before

being sent to the boiler feed water tanks for reuse in the OTSGs.

The produced water is treated in two main stages:

1. Deoiling stage:

• skim tanks;

• Induced Gas Flotation vessels (IGFs); and

• Oil Removal Filters (ORFs).

2. Softening stage:

• warm lime softening to remove silica;

• filtration to remove particulates carried over from theWarm Lime Softener (WLS) units;

• primary SACs to remove the bulk hardness; and

• polishing WACs to remove the last of the hardness.

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Volume 1, Section 7

7.6.2.1 Produced Water Deoiling System

Produced water from the FWKOs and Treaters is cooled and

distributed to the deoiling trains.

The skim tanks are designed for 90% bulk oil removal. Partially

deoiled produced water (200 ppmw or less) from the skim tanks

is drained by gravity to the IGF units to further reduce the oil

content in the water. From the IGF units the water is pumped by

the ORF Feed Pumps to a set of ORFs for final oil removal.

The ORFs (Hydromation filters common to the heavy oil

industry) capture residual traces of dispersed oil from the

produced water. Hydromation filter can remove about 90% of finely dispersed oil droplets from a produced water stream. The

filter feed stream is expected to contain between 10 to 20 ppm

of finely dispersed oil. The deoiled water from the filters will

normally contain less than 2 ppm residual oil and is acceptable

for the WLSs.

Produced water from the ORFs is routed to the deoiled water

tanks. The tanks provide surge capacity and reserve water to

accommodate minor upsets and normal flow fluctuations.

Skim oil from the skim tanks is routed to an oil recycle tank

where water is separated from the oil. Separated oil is

recovered to the free water knock-out drum; water is recycled

back to the skim tank.

Produced water deoiling system equipment required for the

Project is listed in Table 7.6-2.

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Volume 1, Section 7

Table 7.6-2 Phase H Produced Water Deoiling System Equipment



Skim Tank T-0522

Induced Gas Flotation (IGF) Vessel V-0525

IGF Package PK-0525

IGF Oil Pumps P-0533A/B

IGF Oil Filters F-0523A-H

Oil Removal Filter (ORF) Feed Pumps P-0535A/B

Oil Removal Filter Packages (ORFs) PK-0540A/B/C

Deoiled Water Tank T-0555

Deoiled Water Pumps P-0558A/B/C

Oil Recycle Tank T-0545Oil Recycle Pumps P-0548A/B

Water Recycle Pumps P-0550A/B

Deoiling Polymer Injection Package PK-0687, T-0685

7.6.2.2 Water Softening System

The softening trains consist of warm lime softening, filtration,

and then SAC/WAC ion exchange for initial bulk softening and

for final polishing.

The produced water and brackish water make-up are treated for

use as boiler feed water. Some water is lost with the softener

regeneration wastes (sent to disposal wells) and with spent WLS

sludge (sent to landfill). The WLS units remove silica by reacting

with a suspended slurry of magnesium oxide. The WLS units

also help capture iron, suspended solids and trace residual oil.

Addition of MgO triggers the precipitation of Mg(OH)2 and SiO2.

Lime is added to raise the pH of the water to optimize

precipitation. A flocculation polymer is injected to help promoteflocculation. The treated water spills over into the WLS clear

well (overflow tank). The treated water is pumped from the

clear well to the WLS after-filters to capture any particulates

before flowing to the SAC/WAC softening train.

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Volume 1, Section 7

Sludge from the WLS units will be removed as required to

maintain the correct solids inventory and is sent to a centrifuge

for dewatering. The recovered water (centrate) is recycled back

to the WLS unit. Sludge solids are magnesium hydroxide withadsorbed silica and calcium carbonate. Currently, all lime sludge

waste is dewatered (to 50% water by weight) and then disposed

of at a Class II landfill.

Water from the WLS units contains residual hardness equivalent

to the solubility products of calcium and magnesium salts in the

produced water at the operating temperature. It is typically in

the 25 to 30 mg/L range for heavy oil produced water at 90°C

depending on water chemistry. This hardness level must be

reduced to less than 0.5 mg/L to meet steam generatorspecifications. Water is further softened using ion exchange via

a SAC primary unit followed by a WAC polishing unit (SAC/WAC)

both utilizing internal regeneration. The effluent from the ion

exchange polishers will have a target hardness of less than 0.2

mg/L. Each phase has a separate dedicated regeneration

system.

Regeneration waste from the water softening units is neutralized

and sent to the regeneration waste tanks to be pumped to

disposal wells.

Water softening equipment required for the Project is listed in

Table 7.6-3.

7.6.3 Boiler Blowdown Recycle

The Phase H includes boiler blowdown recycle capability. The

ability to recycle blowdown will not be limited by cooling

requirements at high PWSRs as a result of the inclusion of an

external process cooling water system. This system is

necessitated by the decision to treat brackish and producedwater in a common system eliminating the availability of cold

softened brackish water. The common treatment of produced

and brackish water for Phases F to H differs from Phases A to E

where the produced and brackish waters are treated separately.

These different water processing schemes are due to the

differences in brackish water sources. Phases A to E uses

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Volume 1, Section 7

Clearwater B, while Phases F to H use Basal McMurray water

which has higher hardness and TDS concentrations.

Table 7.6-3 Phase H Water Softening System Equipment


Number

Warm Lime Softener T-0560

Clear Well T-0570

Direct Steam Injection Heater X-0559

Sludge Recycle Pumps P-0568A/B

Sludge Blowdown Pumps P-0697A/B

Sludge Centrifuge C-0695

Centrate Sump Z-0690

Centrate Pumps P-0690A/BLime Slurry Pumps P-0756A/B

Lime Storage and Feed Package PK-0750

Magox Storage and Feed Package T-0760

Magox Slurry Pump P-0766

After-Filter Feed Pumps P-0575A/B/C

Warm Lime Softener (WLS) After-Filters Packages PK-0580A-D

Suspended Solids Filters F-0600A-M, F-0605A-M, F-0610A-M

Primary Strong Acid Cation (SAC) Softeners V-0620A-F

Polisher Weak Acid Cation (WAC) Softeners V-0630A-D

Produced Water Brine Saturator T-0655

Brine Pumps P-0657A/B

Acid Storage Tank T-0660

Acid Fume Scrubber V-0666

Acid Regeneration Pump P-0664

Caustic Storage Tank T-0670

Caustic Regeneration Pump P-0674

Neutralization Tank T-0680

Neutralized Waste Pumps P-0682A/B

Coagulant Chemical Injection Skid Package PK-0622, T-0620

Filter Aid Chemical Injection Skid Package PK-0637, T-0635

Sulphite Chemical Injection Package PK-0642, T-0640

Produced Water Brine Saturator T-0655

Hydrochloric Acid Storage Tank T-0660Acid Fume Scrubber Package PK-0666

Dewatering Polymer Chemical Injection Skid Package PK-0782, T-0780

Flocculant Polymer Chemical Injection Skid Package PK-0777, T-0775

Regeneration Waste Water Tanks (a)

Regeneration Waste Water Pumps (a)

Regeneration Waste Water Filters (a)


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Volume 1, Section 7

Blowdown recycle may be limited by cycle up of contaminants

such as TDS, silica, organics, and alkalinity. Based on design

water chemistry for make-up and produced water, cycle up is

not predicted to be a limiting factor

If produced water or brackish water TDS increase it may impact

blowdown recycle. A TDS limit of 8,000 ppm is considered

based on steam generator vendor specifications. A low PWSRs

with high TDS make-up water could limit blowdown recycle

depending on the produced water TDS concentrations. However,

low PWSRs with high TDS concentrations is not expected to be

limiting based on 2nd Stage OTSG trials.

Silica content may limit blowdown recycle directly to the BFWtank. A silica limit of 50 ppm is considered on the boiler

feedwater based on steam generator vendor specifications.

Organic cycle-up is not fully understood. Organic content has

not been an issue in the CPF to date. Typical limits are not

provided by the steam generator vendor; the specification lists

“reasonable quantities”. Based on industry norms this limit is

considered to be in the range of 250 to 700 ppm but would be

dependent on the type of organic and site-specific fouling

performance.

Blowdown disposal will be minimized by use of high steam

quality and maximum blowdown recycle. The flexibility to

operate one of the Phase H OTSGs into blowdown boiler (2nd

Stage OTSG) service is part of the Phase H design. Flexibility to

use either blowdown recycle or a 2nd Stage OTSG will allow

Phase H to optimize operation based on PWSRs and water

chemistry, promote water reuse, minimize blowdown disposal

and reduce make-up water. The differences between 1st and

2nd stage OTSG operation are summarized in Table 7.6-4.

Table 7.6-4 Difference Between 1st and 2nd Stage OTSG Operation

Mode of Operation 1st Stage OTSG 2nd Stage OTSG

Steam Generator Feed BFWBoiler Blowdown, with BFWas required

Steam Quality 80% 75%

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Volume 1, Section 7

7.6.4 Water Disposal – Blowdown and RegenerationWaste

Regeneration waste streams from water treatment units will

flow to disposal wells. Disposal pipelines and wells will be

designed for blowdown volumes during upset or start-up

scenarios.

Water used for backwashing and flushing of the filters and ion

exchange units is recycled to the maximum practical extent.


• CL1H-42-PFD-01-145-01;

• CL1H-42-PFD-01-163-01; and

• CL1H-42-PFD-01-164-01.

7.6.5 Produced Water Disposal

If a CPF upset occurs, produced water may be disposed. The

produced water disposal system for Phase H will be integrated

into the Phases F and G system.


• CL1-42-PFD-01-145-02

7.7 UTILITIES

Reference PFDs for utilities are found in Appendix 1-IX:

• CL1H-42-PFD-07-141-01;• CL1H-42-PFD-07-142-01;

• CL1H-42-PFD-07-142-02;

• CL1H-42-PFD-07-143-01;

• CL1H-42-PFD-07-144-01;

• CL1H-42-PFD-07-145-01;

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Volume 1, Section 7

• CL1H-42-PFD-07-145-03;

• CL1H-42-PFD-07-147-01; and

• CL1H-42-PFD-07-148-01.

7.7.1 Raw Water

Raw (fresh) water in the CPF is used only as fire water, utility

water and for domestic purposes. Fresh water used for domestic

purposes within the CPF is first passed through a carbon filter.

The fresh water tank and pumps to support Phase H are part of

Phase F and included in the Approved Project.

Due to recent CPF design development of Phases F and G, theraw water system will not be shared between Phases A to E and

Phases F to H. As such Phases F to H will require an additional

well to support raw water requirements as described in

Section 8. The raw water volumes for this new well were always

required for the F to H facilities; however, past applications

assumed these volumes would come from existing approved and

operating wells. Both systems will be operated similarly.

However, the Phases F to H system is not expected to use raw

water for domestic purposes and limited use for utility purposes

(fresh water consumption for utilities has been reduced by

substitution of softened boiler feed water for seal flush anddilution). The addition of this well is not anticipated to increase

the total use of raw water; it will simply provide an additional

location for withdrawal.

7.7.2 Instrument/Utility Air

Phase H requires the addition of an instrument air package

(PK-7225).

7.7.3 Nitrogen

A nitrogen package was added in Phase F to supply the

intermittent requirements for operational purging. An additional

nitrogen package is not required for Phase H.

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Volume 1, Section 7

7.7.4 Fuel Gas

Phase H will tie into the Phases F and G fuel gas system with all

required equipment installed as part of Phase F.

7.7.5 Electricity/Cogeneration

Phase H does not include cogeneration facilities. Electricity from

the cogeneration units in Phase F (as well as the grid for back-

up) will be used to supply power to the CPF which including

Phase H.

Reference energy balances are found in Appendix 1-VIII.

7.7.6 Storm Water/Steam Blowdown Ponds

The storm water pond and steam blowdown pond are part of

Phase F. The storm water pond receives surface water runoff

which is tested; clean water is discharged to the local surface

environment; in the event of contamination water is shipped off

site for disposal. The steam blowdown pond receives start-up

blowdown from the OTSGs. This fluid is recycled back into the

process to be used as boiler feed water. Specifications for the

storm water/steam blowdown ponds are listed in Table 7.7-1.

Table 7.7-1 Storm Water/Stream Blowdown Pond Specifications

PondLength

[m]Width[m]

Depth[m]

Volume[m³]

Storm Water Pond, Z-7775 253 92 4.0 to 5.3 21,000

Steam Blowdown Pond, Z-7740 87.2 41.4 3.4 to 3.7 5,700

Note: Z-7775 and Z-7740 were installed in Phase F and is already approved.

7.8

FLUID STORAGE

On spec oil from the Treaters (V-4620/4660) is cooled and

stored in the sales oil tanks (T-6515/6525/6535). The sales oil

tanks will be installed as part of Phase F. Phase H will similarly

leverage off diluent tankage approved as part of Phase F. The oil

is pumped from the tanks to the LACT Unit. Upstream of the

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Volume 1, Section 7

LACT Unit, trim diluent is added to the oil to meet the sales oil

viscosity and density specifications.


• CL1H-42-PFD-06-140-01;

• CL1H-42-PFD-06-141-01 and

• CL1H-42-PFD-06-141-02.

7.8.1 Sales Oil/Off-Spec Storage and Pumps

Sales oil/off-Spec tanks are as part of Phase F to provide

additional storage capacity. An additional pump is included inPhase H, as listed in Table 7.8-1.

Table 7.8-1 Phase H Sales Oil/Off-Spec Storage Equipment


Number

Sales Oil/Off-Spec Tanks (a)

Lease Automatic Custody Transfer (LACT) Booster Pump P-6510D


7.8.2 Diluent Storage and Pumps

Diluent tanks are part of Phase F to provide additional storage

capacity. These tanks may contain either condensate or Oil

Sands Blend A (OSA) diluent. Diluent pumps will be designed to

handle either condensate or OSA as required. Diluent system

equipment required for Phase H is listed in Table 7.8-2.

No new storage tanks required for the Project.

Table 7.8-2 Phase H Diluent System Equipment


Number

Diluent Tanks (a)

Diluent Pumps P-6610 F/G

Diluent/Glycol Exchangers E-4065C1/C2


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Volume 1, Section 7

7.9 STEAM GENERATION

Wet steam (80% quality) will flow from the five Phase H OTSGsto the common steam separator. Dry saturated steam (100%

quality) from the steam separators will flow to the injection

wells at the well pads through high-pressure pipelines.

Blowdown liquids from the steam separators are cooled by boiler

feed water and glycol before flowing to disposal wells or

recycling to the deoiled water tank or BFW tank. Flexibility has

been added to the design to allow one of the Phase H

generators to operate as a blowdown boiler (2nd stage OTSG) by

adding a feed pump, exchanger and separator. The water

balances assume operation of the OTSGs as five primaries which

would result in the highest emissions. The operating limits (e.g.,TDS, silica, pH) for the reboiler operation have not been fully

defined.

An OTSG burns mixed fuel gas; a combination of treated

produced gas and sweet make-up fuel gas from the pipeline.

Steam generation equipment required for the Project is listed in

Table 7.9-1.

Table 7.9-1 Phase H Steam Generation Equipment

Equipment Description Equipment Identification Number

Once Through Steam Generators B-3750/3800/3850/3900/3950

Combustion Air Preheaters E-3785/3835/3885/3935/3985

Combustion Air Blowers K-3770/3820/3870/3920/3970

Flue Gas Recovery (FGR) Blowers K-3790/3840/3890/3940/3990

Steam Separator V-3060

2nd Stage Steam Separator V-2885

BFW / Blowdown Exchangers E-3065 A/B

Blowdown/Glycol Exchanger E-3075

2nd Stage BFW Charge Pumps P-2880 A/B

2nd Stage BFW / Blowdown Exchanger E-2890

Boiler Feed Water (BFW) Booster Pumps P-3010 F/G

Boiler Feed Water (BFW) Charge Pumps P-3015 F/G

Sulphite Injection Pump P-3087C

Chelant Injection Pump P3089C

Filming Amine Chemical Package PK-3081, T-3080

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Volume 1, Section 7

Reference PFDs for the steam generation system are found in

Appendix 1-IX:

• CL1H-42-PFD-02-140-01;

• CL1H-42-PFD-02-142-01;

• CL1H-42-PFD-02-161-01; and

• CL1-42-PFD-02-162-01.

7.10 VAPOUR RECOVERY SYSTEM

Reference PFDs for the vapour recovery system are found in

Appendix 1-IX:

• CL1H-42-PFD-07-140-01; and

• CL1H-42-PFD-07-140-02.

Vapour recovery will be accomplished by a combination of

ejectors and vapour recovery compression. Vapour recovery

compression was selected to provide a more flexible system for

sales oil/diluent/slop vapour recovery. The vapour recovery

system is critical for Phases F to H to effectively remove vapour

generated at elevated sales tank temperatures under hotambient conditions. The cooling loads required by the VRU

compression will be provided by the external cooling system.

The vapours recovered from the ejectors and compression

systems are mixed with treated produced gas and sweet make-

up fuel gas in the fuel gas mix drum and used as fuel in the

OTSGs.

The ejector vapour recovery system is modelled after the

existing CLTP vapour recovery system. Waste gas sources tied

into vapour recovery equipment are detailed in Table 7.10-1.

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Volume 1, Section 7

Table 7.10-1 Phase H Equipment With Vapour Recovery



Skim Tank T-0522

Induced Gas Flotation (IGF) Vessel V-0525


Deoiled Water Tank V-0555

Warm Lime Softener (WLS) T-0560

Clear Well T-0570

Vapour Recovery Unit (VRU) Compressor Package PK-7615

The ejectors use high-pressure pipeline gas which has beenheated in the fuel gas/glycol exchanger to supply the motive

force to educt low-pressure vent gas to the fuel gas pressure.

The discharge gas from the ejectors is mixed with the treated

casing gas and sent to the fuel gas mix drum. Liquids collected

in the VRU ejector suction scrubbers are “blow cased” by

pressurizing the scrubbers with fuel gas to move fluids to the

slop tanks.

The vapour recovery compressor package takes waste gas from,

the sales oil, diluent and slop tanks. The package compresses

the gas and separates out condensed water and diluent. Thecompressed non-condensable gas is sent to the fuel gas mix

drum. Recovered water and hydrocarbon liquids are recycled to

the skim tank and slop tanks respectively.

Phase H will add another VRU compressor package (PK-7615) to

the Phases F and G VRU system.

7.11 SULPHUR RECOVERY FACILITY

Alberta Sulphur Recovery Guidelines identified in the ERCB’s

Interim Directive ID 2001-3, (EUB 2001a) become more

stringent as the sulphur content within the CPF increases. The

ID 2001-3 recovery guidelines are shown in Table 7.11-1. For

in-situ thermal facilities the sulphur inlet rate refers to the

sulphur content of the produced gas.

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Volume 1, Section 7

Table 7.11-1 Alberta Sulphur Recovery Guidelines

Sulphur Inlet Rate

[tonnes/day]

Design Sulphur

Recovery Criteria[%]

Calendar Quarter-Year Sulphur

Recovery Guidelines[%]

< 1 none required none required

1 to 5 70 69.7

>5 to 10 90 89.7

>10 to 50 96.2 95.9

Source: Alberta Energy and Resources Conservation Board Interim Directive ID 2001-3 (EUB 2001a).

Based on current inlet rates sulphur recovery from produced gas

is currently required at the CLTP.

The sulphur ratio (based on bitumen production) has been

adjusted based on field data to refine the design window to

ensure good operability of the SRF. The design sulphur rate for

the Phases A to H is presented in Table 7.11-2.

Table 7.11-2 Design Sulphur Rate

PhasesCumulative BitumenProduction Capacity

Sulphur Content of Casing Gas

Sulphur Ratiokg S/m³ bitumen

A-H 49,284 m³/d 310,000 bbl/d 9.96 tonnes/d 0.202

In accordance with recovery guidelines, sulphur from the

produced gas will be recovered using a non-regenerative

scavenger system.

Inlet sulphur to the CPF after all phases have been constructed

is predicted to peak at a maximum of approximately

9.96 tonnes per day (t/d). This is believed to be conservative

and may be reduced based on re-pressuring of the gas cap with

air. Based on this amount of inlet sulphur, Cenovus will be

required to recover 90% of the inlet sulphur (89.7% sulphurrecovery for the CPF on a calendar quarter year).

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Volume 1, Section 7

7.11.1 Scavenger System

A reference PFD for the scavenger system is found in Appendix

1-IX:

• CL1H-42-PFD-08-140-01.

The scavenger unit uses a non-regenerable triazine-based

scavenger to meet H2S recovery guidelines.

The scavenger is injected into the produced gas and the

combined stream is sparged into the bottom of a liquid-filled

contactor. Spent scavenger overflows into the post contactor

separator where it is separated from the treated gas. Treated

gas is mixed with sweet pipeline natural gas and is burned as

fuel gas in the OTSGs.

Methanol is injected into the spent chemical to prevent gelling.

Spent chemical is trucked off-site and disposed of in a licensed

disposal well.

The scavenger system approved and operating for Phases A to E

is designed for an inlet sulphur rate of 4.7 tonnes/d and a

produced gas rate of 500 x 10³ Sm³/d.

A similar system is approved for Phase F and is dedicated to

Phases F to H produced gas sweetening. The dedicated system

reduces the phase interfaces and provides additional

redundancy.

If scenarios arise where the sulphur emissions cannot be met

with the scavenger system, the oil production will be limited to

meet emission criteria. Phases A to E has two scavenger system

trains currently operating and plot space and design allowanceto construct a third train if required. The design of the three-

train system allows them to run independently of each other,

adding another layer of contingency. Phases F to H will be

constructing a similar design to Phases A to E scavenger

system; two trains being constructed with the option for a third

in the design.

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Volume 1, Section 7

7.12 FLARE SYSTEM

The following reference PFD for the flare system is provided inAppendix 1-IX:

• CL1H-42-PFD-07-146-001.

A common flare stack and Flare Knock Out Drum (FKOD) will be

used for Phases F to H. Any liquids accumulating in the FKOD

will be recycled to the slop tanks.

7.13 BLEND AND DILUENT STORAGE TERMINAL

7.13.1 Blend System

The following reference PFD for the blend system is found in

Appendix 1-IX:

• 08E4225-SK-B-001.

No modifications are contemplated to the blend system as part

of the Project.

Any requirement for additional blend storage capacity will be

assessed by Enbridge as part of Sunday Creek Terminal

modification design. All modifications to the Enbridge Sunday

Creek Terminal will be made under separate applications

according to the applicable regulatory process.

7.13.2 Diluent System

This subsection has been provided for application completeness.

No modifications are contemplated to the diluent system forPhase H.

7.14 OFFSITES PROCESS DESCRIPTION

An overview of the SAGD pipeline gathering and distribution

system and associated well pads is provided in Figure 3.2-4.

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Additionally, Figure 3.2-4 illustrates the location of brackish and

disposal well sites. Borrow pits will be used on an as required

basis to construct off-site facility sites.

7.14.1 Production Well Pad Facilities

The SAGD pads typically range from, but are not limited to, 8 to

16 initial well pairs. A representative well pad with eight well

pairs includes two 3-well pair modules, one 2-well pair module,

a Motor Control Centre (MCC)/instrument air building, a test

separator, a group separator, transfer pumps and a line heater.

The following reference plot plan is found in Appendix 1-VII:

CL1-44-PLT-XXX-001-01.

Well pair modules will feature automated chokes on both the

inner and outer tubing strings to control the amount of flow

from the production well. The modules will also have automated

steam control valves to control the amount of steam being

injected into the inner and outer tubing of the injection wells.

The modules are designed for all modes of operation outlined in

Section 5.

During the ramp-up mode emulsion is first produced by a gas

lift method before production wells are converted to ESP once

the SAGD chamber is adequately developed. During gas lift all

production fluids are directed to the group emulsion header,

which then flows to the group separator. The majority of the lift

gas from the gas lift operation is removed from the emulsion

within the group separator and directed into the casing gas line.

The separated emulsion flows from the group separator vessel

to the group separator transfer pumps, and then is directed to

emulsion line.

For gas lift, the following reference PFD and material

balance are found in Appendix 1-IX and Appendix 1-X,

respectively:

CL1-42-PFD-TYP-XXX-01; and

CL1-42-PFD-TYP-XXX-02.

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When the wells are converted to ESP the inner tubing is

removed. All emulsion fluid will be directed from the outer

tubing to the emulsion group header. During ESP operation all

casing gas from the well casing will be directed to the casing gasheader and the group separator and group separator transfer

pumps are no longer required and may be removed and

re-located for gas lift operations on other SAGD pads.

For ESP, the following reference PFD and material

balance are found in Appendix 1-IX and Appendix 1-X,

respectively:

CL1-42-PFD-TYP-XXX-03; and

CL1-42-PFD-TYP-XXX-04.

Each well pad is proposed to be equipped with a two-phase test

separator. The vessels are designed to accommodate full flow

from one production well pair or Wedge Well™ and test a

maximum of 12 oil production wells on the pad. Additional test

separators will be added (as required) to remain compliant with

well testing regulations. The wet gas phase and the liquid

emulsion are each measured and recombined prior to the

emulsion pipeline. A Basic Sediment and Water (BS&W)

measurement is achieved on the emulsion phase using oil andwater analyzer. A “Texas Sampler” will be installed to obtain

emulsion samples for manual cuts. The total liquid fluid will be

measured by a mass flow meter. The vessel design will feature a

fire case Pressure Safety Valve (PSV). The PSV discharge will be

tied in to a vent stack. The vent stack height will be determined

using a dispersion model so that Occupational Health and Safety

Standards and Alberta Ambient Air Quality Objectives (AAAQOs)

will be met.

Two air compressors will be supplied at each well pad to provide

instrument air. Compressing air at the well pads is moreefficient than piping it from the CPF. Line heaters will be

installed at the lease edge to heat the gas before it is let down

in pressure.

Power will be supplied to each well pad using 25 kV high line. A

transformer will be located at each well pad to supply the

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contain Variable Frequency Drives (VFDs) for the production well

ESPs, breakers for the air compressors, lighting, heat tracing,

fans and heaters. A fibre optic line will be installed on the power

poles for communication between the pad controllers and theCPF control system.

7.14.2 Gathering/Distribution System

The gathering and distribution system for SAGD pads will

include the following pipelines:

• injection steam;

• produced emulsion;

• fuel gas; and

• casing gas.

Power lines will be located across the road from the pipeline

corridor (Appendix 1-VII, Drawing Z03056-PL-SK501-02).

Cenovus will apply to the ERCB and other regulatory agencies

for licenses required for all pipelines and other surface facilities

associated with the well pads, in accordance with existing

regulations.

The steam, fuel gas, emulsion and casing gas systems are

above-ground pipelines supported on a common rack which

includes expansion loops. Pipelines will follow existing ROWs and

roads where practical and cost effective to minimize

environmental impacts. Shut down valves will be installed on

the emulsion and casing gas gathering lines at the pad edge to

protect the lines from high temperature and high pressure. The

fuel gas and steam distribution pipeline will be protected by

PSVs located in the CPF. Pigging facilities will be installed on the

casing gas gathering system.

Pipelines will incorporate design features to facilitate wildlife

crossings. These design features may include:

• raising pipe in selected areas;

• building wildlife crossing structures;

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• making best use of topography to allow for animalpassage; and

• locating crossing sites at existing game trails and inareas of high-quality wildlife habitat.

Stream crossings will be designed to minimize environmental

impacts. Sediment and erosion plans will be developed before

construction at or near water bodies. Applications for stream

crossings will be made to the applicable regulatory bodies before

construction begins.

7.14.3 Brackish/Disposal Facilities

Brackish and disposal facilities are constructed similar to the

SAGD pad facilities, with respect to drilling multiple wells at a

single location and leveraging common surface facilities. These

common surface facilities include but are not limited to:

electrical building, utility transformer, header building, propane

bullet, piping, and wellhead shelters. Brackish and disposal

pipelines are buried and in several cases are common with

existing or proposed future right-of-ways.

Brackish and disposal facilities have been designed to a very

basic standard. Wells are tied into a common header which tiesinto the pipeline which accesses the specific site. This header

and tie in consists of a few valves to isolate and/or control flow

at site.

7.15 ROADS AND INFRASTRUCTURE

7.15.1 Roads

The existing constructed/surveyed roads at the CLTP shown in

Appendix 1-VII, Drawing Z03056-PL-SK501-04 will be extendedto access the remaining pads (SAGD, brackish, disposal) and

future supporting infrastructure as shown in Figure 3.2-4.

Cenovus will attempt to utilize existing ROW clearings wherever

practical and cost-effective to minimize surface disturbance.

Where feasible and mutually agreed to by Cenovus and the

regulatory bodies, Cenovus will attempt to combine the road,

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power line and pipeline ROW to optimize cleared areas and

minimize surface disturbance.

Stream crossings within the Project will be similar to the stream

crossings in the Approved Project. Stream crossings will be

designed to minimize environmental impacts and the number of

crossing has been minimized. Sediment and erosion plans will

be developed prior to construction at or near waterbodies.

Applications for stream crossings will be made to the applicable

regulatory bodies before construction begins.

Surface impacts for the ROW for road access and well pad

access will be determined on an individual basis with the local

ESRD officers. Borrow pits will be used on an as required basisto construct roads.

7.15.2 Infrastructure

Since the Project is an addition to our existing project, CLTP will

primarily utilize existing infrastructure such as camps, laydown

areas, warehouses, power infrastructure and domestic water

treatment to support the Project.

The following additional infrastructure is proposed for theProject:

• field operations offices (field house);

• additional living/recreation facilities for on-site long-termstaff; and

• warehouse/shop/office space for incremental CLTP long-term operations staff.

This additional infrastructure proposed as part of the Project will

be constructed within approved or proposed surface disturbanceareas.

The Project could require other related infrastructure projects

including electrical power lines, fuel gas pipelines and oil

transportation pipelines. These related infrastructure projects

are expected to be applied for separately, as needed.

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Borrow pits will be used on an as required basis to construct

infrastructure sites.

7.15.2.1 Sanitary System

The Project will not affect the existing sanitary system. All

existing facilities, including the lift station, the septic tanks and

the discharge area will remain the same.

7.16 DESIGN STANDARDS

Facilities will be designed in accordance with the provincial and

federal regulations. All relevant and applicable design codes and

standards will be implemented for the execution of the Project.

Standards most likely to be used will include but are not limited

to, the following:

• Canadian Standards Association (CSA);

• Alberta Boiler Safety Association (ABSA);

• American Petroleum institute (API);

• American Society of Mechanical Engineers (ASME);

• American National Standards Institute (ANSI);

• American Concrete Institute (ACI);

• National Association of Corrosion Engineers (NACE);

• American Society for Testing and Materials (ASTM);

• National Building Code of Canada (NBCC);

• Alberta Building Code (ABC);

• Canadian Institute of Steel Construction (CISC);

• Canadian Electrical Code (CEC), Part 1;

• Institute of Electrical and Electronic Engineers (IEEE);

• Instrument Society of America (ISA);

• National Electrical Manufactures of America (NEMA);

• Underwriters Laboratory (UL);

• Tubular Exchanger Manufactures Association (TEMA);

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• American Society of Heating, Refrigeration and AirConditioning Engineers (ASHRAE);

• Air Moving and Conditioning Association (AMCA);

• Sheet Metal and Air Conditioning Contractors NationalAssociation (SMACNA);

• National Fire Protection Association (NFPA);

• Alberta Fire Code (AFC);

• American Conference of Governmental IndustrialHygienist (ACGIH);

• Welding Research Council (WRC);

• Code for Electrical Installations at Oil and Gas Facilities;

• Occupational Health and Safety Act (OH&SA;Government of Alberta 2000e); and

• Oil and Gas (O&G) Facilities Alberta Labour Safety CodesCouncil – Code for Electrical Installations at Oil and GasFacilities.

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