Proposed Cromer Unit No. 3
Application for Enhanced Oil Recovery Waterflood Project
List of Figures
Figure 1 Daly Sinclair Field Area Map
Figure 2 Cromer Unit No. 3 Proposed Boundary
Figure 3 Bakken-Three Forks A Pool
Figure 4 Cromer Unit No. 3 Historical Production
Figure 5 Cromer Unit No. 3 Development Plan
Figure 6 Sinclair Pilot Waterflood Section 4 Production Profile
Figure 7a Cromer Unit No. 3 Primary Recovery – Rate v. Cumulative Oil
Figure 7b Cromer Unit No. 3 Primary Recovery – Rate v. Time
Figure 8a Cromer Unit No. 3 Primary + Secondary Recovery – Rate v. Cumulative Oil
Figure 8b Cromer Unit No. 3 Primary + Secondary Recovery – Rate v. Time
Figure 9 Cromer Unit No. 3 Injection Facilities Process Flow Diagram
Figure 10 Typical Openhole Water Injection Well Downhole Diagram
Figure 11 Planned Corrosion Program
Manitoba Petroleum Branch10
Figure 2 - Daly Sinclair Field (01)
Sharon.BakerTypewritten TextFigure 1
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Manitoba Petroleum Branch30
Figure 13 - Daly Sinclair Bakken & Bakken-Three Forks Pools
(01 60A - 01 60BB & 01 62A 01 62II)
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Sharon.BakerTypewritten TextFigure 4
Sharon.BakerTypewritten Text
Sharon.BakerTypewritten Text
Sharon.BakerTypewritten Text
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Sharon.BakerTypewritten TextFigure 6
Sharon.BakerTypewritten TextPrimary Recovery
Sharon.BakerTypewritten TextPrimary Recovery
Sharon.BakerTypewritten TextFigure 7a
Sharon.BakerTypewritten TextFigure 7b
Sharon.BakerTypewritten Text
Sharon.BakerTypewritten Text
Sharon.BakerTypewritten TextPrimary + Secondary Recovery
Sharon.BakerTypewritten TextPrimary + Secondary Recovery
Sharon.BakerTypewritten TextFigure 8b
Sharon.BakerTypewritten TextFigure 8a
Sharon.BakerTypewritten Text
Sharon.BakerTypewritten TextConversions
Sharon.BakerTypewritten Text
Sharon.BakerTypewritten TextWaterflood Response
Sharon.BakerTypewritten Text
Sharon.BakerTypewritten TextFigure 9
Sharon.BakerTypewritten Text
TYPICAL OPEN HOLE WATER INJECTION WELL (WIW) DOWNHOLE DIAGRAMWELL NAME: Tundra Cromer Unit No. 3 HZNTL Open Hole WIW WELL LICENCE:
Prepared by WRJ (average depths) Date: 2012
Elevations :
KB [m] KB to THF [m] TD [m] 2400.0
GL [m] CF (m) PBTD [m]
Current Perfs: Open Hole 950.0 to 2400.0
Current Perfs: to
KOP: 700 m MD Total Interval to
Tubulars Size [mm] Wt - Kg/m Grade Landing Depth [mKB]
Surface Casing 244.5 48.06 H-40 - ST&C Surface to 140.0
Intermed Csg (if run) 177.8 34.23 & 29.76 J-55 - LT&C Surface to 950.0
Open Hole Latera none none none 950.0 to 2400.0
Tubing 60.3 or 73.0 - TK-99 6.99 or 9.67 J-55 Surface to 940.0
Date of Tubing Installation: Length Top @
Item Description K.B.--Tbg. Flg. 0.00 m KB
Corrosion Protected ENC Coated Packer (set within 15 m of Intermed Csg shoe)
60.3 mm or 73 mm TK-99 Internally Coated Tubing
SC = 140mKB TK-99 Internally Coated Tubing Pup Jt
Coated Split Dognut
Annular space above injection packer filled with inhibited fresh water
Bottom of Tubing mKBRod String :
Date of Rod Installation:
Bottomhole Pump:
Directions:
KOP = ~ 700 mMD
Inhibited Annular Fluid
Injection Packer set within 15 m of Intermediate Casing Shoe
Intermediate Casing Shoe
Open Hole Fractures
Tundra Oil And Gas Partnership
0
Sharon.BakerTypewritten TextFigure 10
Sharon.BakerTypewritten Text
Sharon.BakerTypewritten Text
** subject to final design and engineering
Cromer Unit No. 3
EOR Waterflood Project Planned Corrosion Control Program ** Source Well
• Continuous downhole corrosion inhibition • Continuous surface corrosion inhibitor injection • Downhole scale inhibitor injection • Corrosion resistant valves and internally coated surface piping
Pipelines
• Source well to 3-4-8-29 Water Plant – Fiberglass • New High Pressure Pipeline to Unit 9 injection wells – 2000 psi high pressure
Fiberglass Facilities
• 3-4-8-29 Water Plant and New Injection Pump Station o Plant piping – 600 ANSI schedule 80 pipe, Fiberglass or Internally coated o Filtration – Stainless steel bodies and PVC piping o Pumping – Ceramic plungers, stainless steel disc valves o Tanks – Fiberglass shell, corrosion resistant valves
Injection Wellhead / Surface Piping
• Corrosion resistant valves and stainless steel and/or internally coated steel surface piping
Injection Well
• Casing cathodic protection where required • Wetted surfaces coated downhole packer • Corrosion inhibited water in the annulus between tubing / casing • Internally coated tubing surface to packer • Surface freeze protection of annular fluid • Corrosion resistant master valve • Corrosion resistant pipeline valve
Producing Wells
• Casing cathodic protection where required • Downhole batch corrosion inhibition as required • Downhole scale inhibitor injection as required
Figure 11