Horizontal San Andres Play Russell K. Hall 2 Russell K. Hall - PowerPoint PPT Presentation

1 Northwest Shelf Horizontal San Andres Play Russell K. Hall

2 Russell K. Hall • Graduated by University of Oklahoma, BS Mechanical Engineering, 1978 • Worked for 3 E&P Companies (Amoco Production, Cleary Petroleum, Southwest Royalties) for 4 years • Worked in Energy Lending (Bank of America) for 14 years • Founded Consulting Engineer Firm in 1996

3 HUMILITY • Reservoirs are Complex • Compartmentalization ! • Additional Data Does Not Simplify Analysis • Interpretations Will Always Change • Estimates are ESTIMATES • “Ball Park” Perspective

4 Permian Basin MIDLAND

5 San Andres Development in Northwest Shelf • 1936 – Duggan no. 1 – 396 bopd • 1937 – Slaughter no. 1 – 512 bopd • 1950’s & 1960’s – Waterflood Development – Cumulative Production 560 Million Barrels • Cumulative Today – 4 Billion Barrels + • 2013 – Horizontal San Andres Play • Today HZ SA Play ≈ 65 wells, 9,000 bopd

6 Northwest Shelf Horizontal San Andres Play • Geologic Setting • Well Performance • Reservoir Interpretation • Future Development

7 Geologic Setting

8 Carbonate Platform Environment Northwest Midland Shelf Basin Dolomite (CaMg(CO 3 ) 2 ), Anhydrite (CaSO 4 )

9 Restricted Marine Basin After Ramondetta

10 Transgressive / Regressive Cycles Result in Multiple SA Intervals

11 5,227 5,318 5,366 5,396

12

13

14 Well Performance

15 Typical Well Performance

16 Typical Well Performance Depressurizing Near Wellbore

17 Typical Well Performance Increasing Oil Cut

18 Typical Well Performance Stabilized Oil Cut

19 10000 LINEAR FLOW -1/2 SLOPE BARRELS OF FLUID PER DAY 1000 PUMP PROBLEMS? 100 1 10 100 1000 CUM DAYS

20 Typical Well Performance Flow Will Eventually Change to Boundary Dominated Flow

21 Typical Well Performance Hyperbolic “n” Factor May Decrease

22 50.0% 45.0% Initially Well 40.0% Produces Only 35.0% Water 30.0% 25.0% SNOW STORM 20.0% 15.0% MESSING WITH SI 39 PUMP DAYS 10.0% 5.0% 0.0% 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 CUM FLUID (BBLS)

23 50.0% 45.0% 40.0% Depressurize 35.0% Reservoir 30.0% Oil Flows – Cut 25.0% Increases SNOW STORM 20.0% 15.0% MESSING WITH SI 39 PUMP DAYS 10.0% 5.0% 0.0% 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 CUM FLUID (BBLS)

24 50.0% 45.0% 40.0% SNOW 35.0% STORM 30.0% 25.0% SNOW STORM 20.0% 15.0% MESSING WITH SI 39 PUMP DAYS 10.0% 5.0% 0.0% 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 CUM FLUID (BBLS)

25 50.0% 45.0% 40.0% 35.0% SI FOR 30.0% 39 DAYS 25.0% SNOW STORM 20.0% 15.0% MESSING WITH SI 39 PUMP DAYS 10.0% 5.0% 0.0% 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 CUM FLUID (BBLS)

26 Well Performance Hypothesis • Reservoir Requires Depressurizing to Produce Oil • Near Wellbore Pressure Falls to Bubble Point Pressure • Expanding Gas Alters Oil Properties (Three Phase Relative Permeability), Oil Flows • Shut-In Allows Reservoir Pressure to Stabilize • Repeat Depressurizing After Shut-In

Oil Cut Performance 27 40% 20 18 35% Chambliss Interval 16 30% 14 25% 12 OIL CUT (PERCENT) WELL COUNT 20% 10 8 15% 6 10% 4 5% 2 0% 0 0 50,000 100,000 150,000 200,000 250,000 CUM TOTAL FLUID (BBL) P1 COMPLETIONS P2 HIGH COMPLETIONS P1 WELL COUNT P2 HIGH WELL COUNT

Oil Cut Performance 28 40% 20 18 35% Brahaney Interval 16 30% 14 25% 12 OIL CUT (PERCENT) WELL COUNT 20% 10 8 15% 6 10% 4 5% 2 0% 0 0 50,000 100,000 150,000 200,000 250,000 CUM TOTAL FLUID (BBL) P1 COMPLETIONS P2 HIGH COMPLETIONS P1 WELL COUNT P2 HIGH WELL COUNT

Oil Cut Performance 29 40% 20 18 35% 16 30% 14 25% 12 OIL CUT (PERCENT) WELL COUNT 20% 10 8 15% 6 10% 4 5% 2 0% 0 0 50,000 100,000 150,000 200,000 250,000 CUM TOTAL FLUID (BBL) P1 COMPLETIONS P2 HIGH COMPLETIONS P1 WELL COUNT P2 HIGH WELL COUNT

30 Oil Cut Performance • Plots of Oil Cut vs Cumulative Fluid • Normalized to Time Zero • Compare Chambliss (Upper) to Brahaney (Lower) • Chambliss and Brahaney Exhibit Similar Oil Cut Performance

31 HZ San Andres -2 P2 Performance P5 Input data samples P10 LMS FIT (Normal Distribution) P20 Oil Cut Exhibits P30 Normal P40 P50 P60 (Gaussian) P70 P80 Distribution P90 P95 P98 0 10 20 30 40 OIL CUT (PERCENT)

32 Oil EUR Analysis -2 P2 P5 78,910 112,444 P10 P20 SHORT LATERALS LONG LATERALS P30 SWANSON'S MEAN SWANSON'S MEAN P40 50,500 BBL / 1000 FT 70,500 BBL / 1000 FT 46,475 64,374 P50 P60 P70 P80 27,372 36,854 P90 P95 P98 1,000 10,000 100,000 1,000,000 Oil EUR (barrels) SHORT LATERAL LONG LATERAL

33 Oil EUR Analysis 70% 66.7% 60% 57.6% 50% PEAK OIL CUT 40% 30% 27.8% 27.3% 20% 15.2% 10% 5.6% 0% <10% OIL CUT 10% TO 20% OIL CUT > 20% OIL CUT SHORT LATERAL WELLS LONG LATERAL WELLS

34 Reservoir Interpretation

35 Genesis of Northwest Shelf ROZ Rainfall Causes Lateral Water Movement Laramide Orogeny Original Depositional Conditions Change in Hydrodynamic Conditions After Trentham, Melzer

36 ROZ Fairways Lateral Water Movement After RPSEA

37 ROZ Evidence • Microbes change water-wet system to oil-wet system • H 2 S Produced by Microbes • Water Saturation • Additional Dolomitization • Tilting Oil / Water Contact • Log Presentation

38 Shifting of Relative Permeability Oil Perm > Water Perm

39 Shifting of Relative Permeability Water Perm > Oil Perm

40 Below Bubble Point Gas Saturation Increases Relative Perm of Non-Wetting Phase Shifts

41 Oil / Water Contact Tilt

42 Horizontal San Andres Play • Conclusion 1 – Chambliss and Brahaney Intervals Are In Communication • Conclusion 2 – Productive Pays are Partially Swept Residual Oil Zones (ROZ) • Conclusion 3 – Larger Fracs Improve Performance In Certain Areas

43 Stimulation Analysis Fair Correlation to Frac Volume

44 Horizontal San Andres Play • Conclusion 1 – Chambliss and Brahaney Intervals Are In Communication • Conclusion 2 – Productive Pays are Partially Swept Residual Oil Zones (ROZ) • Conclusion 3 – Larger Fracs Improve Performance in Certain Areas • Conclusion 4 – Performance Controlled by Rock Fabric and Fluid Saturations

45 Future Development

46 Economic Parameters • CAPEX Increases With Oil Price $ 200,000 For Every $ 10 Per bbl • LOE - $ 10,000 per Month, $ 2.00 per bbl Oil, $ 0.20 per bbl Water • 100% WI, 75% NRI • Oil Deduct $ 1.35 Below Posted

47 Economics Look Good 250 200 RATE-OF RETURN (PERCENT) 150 100 50 0 20 30 40 50 60 70 80 90 OIL PRICE ($ PER BBL) 10 PERCENT OIL CUT 15 PERCENT OIL CUT 20 PERCENT OIL CUT

48 Economics Look Good 6.00 5.00 4.00 PAYOUT (YRS) 3.00 2.00 1.00 0.00 20 30 40 50 60 70 80 90 OIL PRICE ($ PER BBL) 10 PERCENT OIL CUT 15 PERCENT OIL CUT 20 PERCENT OIL CUT

49 Future Development • Expect Continued Drilling • Operators May Slow Development Until Oil Price Improves • Regional Geologic Setting Favors Expansive Development • More Well Control Needed To Define Boundaries

50 Thank You Russell K. Hall, P.E. Russell K. Hall and Associates, Inc. Midland, Texas 432-683-6622