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

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

Feb 20, 2024 320 likes •832 views

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

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Russell K. Hall

Northwest Shelf Horizontal San Andres Play

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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
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HUMILITY

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

MIDLAND

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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
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Northwest Shelf Horizontal San Andres Play

  • Geologic Setting
  • Well Performance
  • Reservoir Interpretation
  • Future Development
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Geologic Setting

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Carbonate Platform Environment

Northwest Shelf Midland Basin

Dolomite (CaMg(CO3)2), Anhydrite (CaSO4)

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After Ramondetta

Basin Restricted Marine

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Transgressive / Regressive Cycles Result in Multiple SA Intervals

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

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Well Performance

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Typical Well Performance

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Typical Well Performance

Depressurizing Near Wellbore

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Typical Well Performance

Increasing Oil Cut

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Typical Well Performance

Stabilized Oil Cut

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19 100 1000 10000 1 10 100 1000 BARRELS OF FLUID PER DAY CUM DAYS

PUMP PROBLEMS? LINEAR FLOW

  • 1/2 SLOPE
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Typical Well Performance

Flow Will Eventually Change to Boundary Dominated Flow

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Typical Well Performance

Hyperbolic “n” Factor May Decrease

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22 0.0% 5.0% 10.0% 15.0% 20.0% 25.0% 30.0% 35.0% 40.0% 45.0% 50.0% 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 CUM FLUID (BBLS)

SNOW STORM SI 39 DAYS MESSING WITH PUMP

Initially Well Produces Only Water

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23 0.0% 5.0% 10.0% 15.0% 20.0% 25.0% 30.0% 35.0% 40.0% 45.0% 50.0% 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 CUM FLUID (BBLS)

SNOW STORM SI 39 DAYS MESSING WITH PUMP

Depressurize Reservoir Oil Flows – Cut Increases

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24 0.0% 5.0% 10.0% 15.0% 20.0% 25.0% 30.0% 35.0% 40.0% 45.0% 50.0% 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 CUM FLUID (BBLS)

SNOW STORM SI 39 DAYS MESSING WITH PUMP

SNOW STORM

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25 0.0% 5.0% 10.0% 15.0% 20.0% 25.0% 30.0% 35.0% 40.0% 45.0% 50.0% 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 CUM FLUID (BBLS)

SNOW STORM SI 39 DAYS MESSING WITH PUMP

SI FOR 39 DAYS

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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
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Oil Cut Performance

2 4 6 8 10 12 14 16 18 20 0% 5% 10% 15% 20% 25% 30% 35% 40% 50,000 100,000 150,000 200,000 250,000

WELL COUNT OIL CUT (PERCENT) CUM TOTAL FLUID (BBL)

P1 COMPLETIONS P2 HIGH COMPLETIONS P1 WELL COUNT P2 HIGH WELL COUNT

Chambliss Interval

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2 4 6 8 10 12 14 16 18 20 0% 5% 10% 15% 20% 25% 30% 35% 40% 50,000 100,000 150,000 200,000 250,000

WELL COUNT OIL CUT (PERCENT) CUM TOTAL FLUID (BBL)

P1 COMPLETIONS P2 HIGH COMPLETIONS P1 WELL COUNT P2 HIGH WELL COUNT

Oil Cut Performance

Brahaney Interval

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2 4 6 8 10 12 14 16 18 20 0% 5% 10% 15% 20% 25% 30% 35% 40% 50,000 100,000 150,000 200,000 250,000

WELL COUNT OIL CUT (PERCENT) CUM TOTAL FLUID (BBL)

P1 COMPLETIONS P2 HIGH COMPLETIONS P1 WELL COUNT P2 HIGH WELL COUNT

Oil Cut Performance

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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

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P2 P5 P10 P20 P30 P40 P50 P60 P70 P80 P90 P95 P98

  • 2

10 20 30 40

OIL CUT (PERCENT)

Input data samples LMS FIT (Normal Distribution)

Oil Cut Exhibits Normal (Gaussian) Distribution

HZ San Andres Performance

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36,854 64,374 112,444 27,372 46,475 78,910 P2 P5 P10 P20 P30 P40 P50 P60 P70 P80 P90 P95 P98

  • 2

1,000 10,000 100,000 1,000,000

Oil EUR (barrels)

SHORT LATERAL LONG LATERAL

SHORT LATERALS SWANSON'S MEAN 70,500 BBL / 1000 FT LONG LATERALS SWANSON'S MEAN 50,500 BBL / 1000 FT

Oil EUR Analysis

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33 0% 10% 20% 30% 40% 50% 60% 70% <10% OIL CUT 10% TO 20% OIL CUT > 20% OIL CUT

15.2% 27.3% 57.6% 5.6% 66.7% 27.8% PEAK OIL CUT

SHORT LATERAL WELLS LONG LATERAL WELLS

Oil EUR Analysis

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Reservoir Interpretation

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Genesis of Northwest Shelf ROZ

Original Depositional Conditions Change in Hydrodynamic Conditions

After Trentham, Melzer

Rainfall Causes Lateral Water Movement

Laramide Orogeny

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ROZ Fairways

Lateral Water Movement

After RPSEA

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ROZ Evidence

  • Microbes change water-wet system to oil-wet

system

  • H2S Produced by Microbes
  • Water Saturation
  • Additional Dolomitization
  • Tilting Oil / Water Contact
  • Log Presentation
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Shifting of Relative Permeability

Oil Perm > Water Perm

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Shifting of Relative Permeability

Water Perm > Oil Perm

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Below Bubble Point Gas Saturation Increases

Relative Perm

  • f Non-Wetting

Phase Shifts

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Oil / Water Contact Tilt

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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

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Stimulation Analysis

Fair Correlation to Frac Volume

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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

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Future Development

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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
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Economics Look Good

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

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Economics Look Good

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

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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

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Thank You

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