Moving from Secondary to Tertiary Recovery Stages. 9 TH ANNUAL WYOMING EORCO2 CONFERENCE JULY 14-16, 2015 Casper, WY By Jim Mack MTech Ventures LLC

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1 Moving from Secondary to Tertiary Recovery Stages 9 TH ANNUAL WYOMING EORCO2 CONFERENCE JULY 14-16, 2015 Casper, WY By Jim Mack MTech Ventures LLC 1

2 Outline Reservoir Data Geologic Data Formation Data Fluid Data Primary & Secondary Performance EOR Development Closing 2

3 This is a Workshop open for Discussion 3

4 Reservoir Data Total Surface Area, AC: no. of wells, pattern Well Spacing, AC: < 80 acre spacing Average Net Pay: thin vs. thick Type Primary Producing Drive: solution gas drive, fluid expansion, waterdrive Depth: Injection Pressure Temperature 4

5 Geologic Data Formation: Type (Sandstone/Carbonate): clean vs dirty sandstone, fractured carbonate; dual porosity Reservoir Structure Reservoir Isopach Faults, Compartmentalization, Unconformities 5

6 Formation Data Porosity, % (Avg. & Range): Permeability Average md: Permeability Range, md: Permeability Variation, Kv: Wettability Clays Fractures (Y/N) 6

7 Sample Permeability (md) Dykstra-Parsons Permeability Variation Log-Normal Permeability Variation 2 2% 20% 50% 80% 98% Percent Greater Than K v = k avg - k σ k avg K v = K v = 0.7

8 Waterflood Oil Recovery Fluid Distribution During Waterflood of Water-Wet Rock Early in Drive Midway in Drive Flood-out Fluid Distribution During Waterflood of Oil-Wet Rock Early in Drive Midway in Drive Economic Limit

9 Displacement Efficiency Oil Displacement by Water, Oil-wet Sand Oil Displacement by Water, Water-wet Sand 9

10 Core Treatment Parameters Kf / Ki - Final permeability / initial permeability (Kf / Ki) t - Treatment-induced permeability damage (Kf / Ki) s - Fresh water sensitivity after treatment (Kf / Ki) c - Fresh water sensitivity for a comparable untreated plug 10

11 Kf / Ki Core Results F Oligocene Aged Sandstone Crude Prod. Water t s c 11

12 Fluid Data Oil Properties Gravity Viscosity Formation Volume Factor Relative Permeability Water Properties Salinity Connate Water Saturation Hardness Relative Permeability Mobility Ratio 12

13 Relative Permeability (Fraction) Relative Permeability (Fraction) Typical Water-Oil Relative Permeability Characteristics Strongly Water-Wet Rock Strongly Oil-Wet Rock Oil Oil Water 0.20 Water Water Saturation (% PV) Water Saturation (% PV) 13

14 Fractional Flow of Water (fw) Fractional Flow of Water (fw) Fractional Flow Curves Strongly Water-Wet Rock μ o = 1 cp, μ w = 0.5 cp Strongly Oil-Wet Rock μ o = 1 cp, μw = 0.5 cp Water Saturation (%Pv) Water Saturation (%Pv) 14

15 Mobility Ratio (M) A ratio of the water mobility in the water bank to the oil mobility in the oil bank M = (K rw /μ w ) / (K ro / μ o ) Use end point relative permeability WATER K rw /µ w OIL K ro /µ o

16 Permeability Variation, Kv Effect of Permeability Variation & M on Sweep Efficiency WOR = Oil Recovery

17 Primary & Secondary Performance Primary Producing Mechanism Fluid Expansion Solution Gas Drive Oil Recovery % OOIP; 3-20%OOIP; Waterdrive ->30% OOIP Time Rate Production Curve 17

18 BOPD Primary Production Primary Decline Curves Decline 1 Decline 2 Decline Years 18

19 Monthly Production & Conc (mg/l) Total Field Production 100,000 10,000 BOPM BWPM 10 1 May 86 Aug 87 Dec 88 May 89 Aug 90 Sept 91 Jan 93

20 Primary & Secondary Performance Secondary Recovery Performance Oil Response Water Breakthrough Oil Recovery % OOIP Injection Well Performance Production/Injection Issues Water Quality - scale, bacterial, etc. Production - fluid levels, total fluid changes Well Integrity 20

21 Waterflood Patterns Two-Spot Three-Spot Regular Four-Spot Skewed Four-Spot Five-Spot Direct Line Drive Staggered Line Drive Seven-Spot Inverted Seven-Spot Normal Nine-Spot Inverted Nine-Spot 21

22 Monthly Production (BBLS, Conc, mg/l) Input / Output Ratio Total Field Production 100, , Jan. 87 BOPM BWPM Input / Output Jan. 89 Jan. 91 Jan. 93 Jan. 95 Jan

23 Oil and Water Production Water-Oil Production Case Study 100,000 Projected Start Polymer Flood Actual Start Polymer Flood End Polymer Flood Estimated Polymer Flood 10,000 Estimated Waterflood 1,

24 Producing Water-Oil Ratio Cumulative Oil Recovery vs. WOR A B C A B V = 0.80, M = 5 V = 0.65, M = 5 V = 0.50, M = Cumulative Oil Recovery (Coverage C )

25 Cumulative Pressure (PSI x Days/BBL) Hall Plot Injection Typical Hall Slopes A B B C Cumulative Water Injection (BBLS)

26 Cumulative Pressure (psi days) Hall Plot Curve Shapes Injectivity Loss Good Part Formation Cumulative Injection (BBLS) 26

27 EOR Development Address Issues Limiting Waterflood Recovery Water Issues Spacing Injectivity Limitations Sweep High Residual Oil Saturation 27

28 Waterflood Oil Recovery N P = OOIP x E D x E AS X E VS N P : Waterflood oil recovery E D : Displacement efficiency E AS : Aerial sweep efficiency E VS : Vertical sweep efficiency

29 Water Quality Filter injection water Monitor, Monitor, Monitor! Salinity changes Solids content Scale formation Corrosion Bacteria

30 Cambridge Field Pilot Test Results 100,000 10,000 Oil Production i Primary Forecas t S econdary AS P F lood Actual A c tual S im ulated His tory Match Primary Alkaline-S urfac tant-polymer F lood 1,

31 EOR Development Design EOR Process to Maximize Efficiency, Oil Recovery & Economics Waterflood Issues to Address Facility Design Personnel 31

32 Closing To have a successful EOR Project, everything that is necessary for a successful waterflood is required with the integration of the EOR process in the reservoir coupled with proper surface facilities 32

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