FracproPT Short Course

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Fracture Modeling

By Pinnacle Technologies

FracproPT System Highlights Estimates fracture geometry and proppant placement in real-time by net pressure history matching Provides unique tool to capture what is learned from direct fracture diagnostics through calibrated model settings Performs near-wellbore tortuosity / perf friction analysis allows identification and remediation of potential premature screenout problems Integrated reservoir simulator for production forecasting and matching Optimizes fracture treatment economics Supports remote access via modem or internet Contains preloaded libraries of stimulation fluids, proppants, and rock properties for many lithologies

FracproPT Module InteractionCalibrated Model Settings Wellbore Information Log/layer Information DataAcqPT Real-Time Data Acquisition

Treatment Data

Production Data

FracproPT Fracture Design

FracproPT Fracture Analysis

FracproPT Production Analysis

Treatment Schedule

Estimated Fracture Geometry

Production Forecast or Match

FracproPT Economic Optimization

Motivation for Frac Engineering & DiagnosticsHydraulic fracturing is done for well stimulation NOT for proppant disposal

Fracture Pressure Analysis - Advantages Basic analysis data collected (in some sense) during every frac treatment Relatively inexpensive and quick diagnostic technique to apply Provides a powerful tool for on-site diagnosis of fracture entry problems Allows on-site design refinement based on observed fracture behavior

Fracture Pressure Analysis - Limitations Fracture Entry Friction Evaluation Using surface pressure increases results uncertainty Problematic near-wellbore friction level variable

Net Pressure History Matching Indirect Diagnostic Technique - frac geometry inferred from net pressure and leakoff behavior Solution non-unique careful & consistent application required for useful results Technique most useful when results are integrated or calibrated with results of other diagnostics Production data & welltest analysis Direct fracture diagnostics

Example Application Pressure Out on Pad Formation: Naturally fractured dolomite @ 8200 (gas) 5-1/2 casing frac string, max. surface Completion: pressure 6000 psi; 70 perf interval shot at 4 SPF, 90, 0.45 diameter hole; Previously acidized with 70 gallons/ft 20% HCl Situation: Declining injectivity leading to pressure-out on pad Diagnosis: Severe near-wellbore fracture tortuosity Solution: 1 and 2 PPG proppant slugs very early in the pad to screen out fracture multiples

Example Application Pressure Out on Pad20.00 6000 16.00 4800 12.00 3600 8.00 2400 4.00 1200 0.00 0

Proppant Conc (ppg) Surf Press [Csg] (psi)

1400 psi friction reduction (1st slug)

Btm Prop Conc (ppg) Slurry Flow Rate (bpm)Max surface pressure 6000 psi no tortuosity at end of pumping

S/D#2: 300 psi tortuosity S/D#1: 1700 psi tortuosity; small perf fric.

Increased max prop conc

0.0

28.0

56.0

84.0

112.0

140.

Example Application Estimation of Realistic Fracture Half-Length Formation: Hard sandstone @ 7600 (gas) in West Texas 5-1/2 casing frac string; 40 perf interval Completion: shot with 4 SPF, 90 phasing, 0.31 diameter holes Situation: Disappointing production performance for expected 600 ft fracture half-length (based on fracture growth design without real-data feedback) Diagnosis: Sand/shale stress contrast much lower than estimated, resulting in significant fracture height growth and a much shorter fracture half-length (250) Utilize fracture pressure analysis to optimize Solution: fracture treatment design

Example Application Estimation of Realistic Fracture Half-LengthGeometry inferred design without real-data feedback High stress contrast 0.3 psi/ft (based on Dipole Sonic log interpretation)50.00 100.0 40.00 80.0 30.00 60.0 20.00 40.0 10.00 20.0 0.00 0.0

Btm Prop Conc (ppg) Slurry Rate (bpm)

Net Pressure (A) (psi) Prop Conc (ppg)

2 50

1 40

1 30

8 20

4 10

0.0

20.0

Time (min)

40.0

60.0

80.0

0 100.0

Example Application Estimation of Realistic Fracture Half-LengthGeometry inferred design without real-data feedback Observed net pressure does not match design net pressure responseNet Pressure (A) (psi) Prop Conc (ppg) Observed Net (psi)

2000 50.00 2000 1600 40.00 1600 1200 30.00 1200 800 20.00 800 400 10.00 400 0 0.00 0

Btm Prop Conc (ppg) Slurry Rate (bpm)

5 1

4 8

3 6

2 4

1 2

0.0

20.0

Time (min)

40.0

60.0

80.0

0 100.0

Example Application Estimation of Realistic Fracture Half-LengthGeometry inferred design without real-data feedback50.00 100.0 2000 40.00 80.0 1600 30.00 60.0 1200

Btm Prop Conc (ppg) Slurry Rate (bpm) Observed Net (psi)

Net Pressure (A) (psi) Prop Conc (ppg) Net Pressure (psi)

5

4

3

Geometry inferred from net pressure matching

20.00 40.0 800 10.00 20.0 400 0.00 0.0 0

2

1

Time (min) Lower stress contrast (0.1 psi/ft) required to match observed net pressure

0.0

20.0

40.0

60.0

80.0

100.0

Confirmed with shale stress test in subsequent wells

Example Application -- Tip Screen-out Strategy To Obtain Sufficient Conductivity Formation: High permeability layered sandstone at 6000 ft (oil) Deviated wellbore, 3-1/2 tubing frac string Completion: 30 perf interval shot 4 SPF, 180 phasing oriented perfs, 0.5 diameter holes Situation: Relatively poor post-frac production response for high perm reservoir Diagnosis: Insufficient propped fracture conductivity Increase treatment size, and utilize on-site fracture Solution: pressure analysis to consistently achieve tip screenout for enhanced fracture conductivity

Example Application -- Tip Screenout Strategy River Unit 2K-15 To Obtain Sufficient ARCO Kuparuk A4 sand 6217'-6247' TVD 12/22/96 Conductivity50.00 100.0 750.0

Btm Prop Conc (ppg) Slurry Rate (bpm) Observed Net (psi)Tip screen-out initiation

Prop Conc (ppg) Net Pressure (psi)

50.00 750.0

40.00 80.0 600.0

Pad fluid volume adjusted based on leakoff behavior following crosslink gel minifrac Breakdown injection

40.00 600.0

30.00 60.0 450.0

30.00 450.0

Minifrac20.00 40.0 300.0 20.00 300.0

10.00 20.0 150.0

10.00 150.0

0.00 0.0 0.0

0.0

60.0

Time (mins)

120.0

180.0

240.0

300.0

0.00 0.0

Pad sizing for TSO design was done utilizing leakoff calibration with minifrac. The net pressure match shows a significant increase in pressure due to tip screen-out initiation

Net pressure match

Pinnacle Technologies

Example Application -- Tip Screen-out Strategy To Obtain Sufficient Conductivity Production response in Kuparuk A sand limited by fracture conductivity Tip screen-out obtained in more than 90% of treatments Sizing of pad size using calibration of leakoff coefficient key to success On-site real-time closure stress analysis implemented on every treatment to ensure proper pad size is pumped

Definition Of Net PressureNet Pressure is the Pressure Inside the Fracture Minus the Closure Pressure Net Pressure = 2,500 - 2,000 = 500 psi

Balloon Analogy For Opening Fracture With Constant Radius

Fluid Leakoff And Slurry EfficiencyLOW SLURRY EFFICIENCYVfrac (t) efficiency (t) = Vpumped (t)

Short Fracture

High Filtration

HIGH SLURRY EFFICIENCY Longer Fracture Low Filtration

Net Pressure Vs. Friction Pressure

Net Pressure Matching

Basic Fracture P ressure A nalysis Steps

1 2

Pre-frac com pletion and fracture design Repeat process in succeeding stages or w ells

Determ ine fracture closure stress and m atch perm eability Characterize friction param eters using rate stepdow n tests Determ ine observed net pressure

3

Post-frac m odeling review and incorporate other fracture diagnostics

4

M atch m odel net pressure to observed net pressure

Perform treatm ent

Explore / bound altern ative explanations for observed net pressure

Interpret m odel results, m ake engineering decisions

Different Models 2D models Perkins, Kern and Nordgren (PKN) Christianovitch, Geertsma and De Klerk (CGD) Radial Model 3D models Pseudo 3D models Lumped 3D models Full 3D models Non-planar 3D models

Fracture Design and Analysis EvolutionModeling without Real-Data Feedback Early designs (pre-1980) did not incorporate feedback from real data Fractures at that time were still smart enough to stay in zone

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Fracture Design and Analysis EvolutionModeling without Real-Data Feedback Early designs (pre-1980) did not incorporate feedback from real data Fractures at that time were still smart enough to stay in zone But measured net pressure was generally MUCH higher than model net pressureW e llb o r e

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