Assessing Multiple Data Sources to Understand Frac ... UNCONVENTIONAL RESERVOIR ANALYSIS Assessing the Impact of Early-Time Operations • Williams-Kovacs Pre$Drill Reservoir(Sample(and(Log(Analysis

Assessing Multiple Data Sources to Understand Frac Property Evolution Over Time: Do Early-Time Operations

Impact Long-Term Performance?

Jesse D. Williams-Kovacs, University of Calgary and TAQA North Ltd.

CANADIAN BUSINESS CONFERENCES ARTIFICIAL LIFT & HORIZONTAL PRODUCTION COST REDUCTION INITIATIVE 2015 29-30 APRIL 2015 • CALGARY, ALBERTA

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OUTLINE

Assessing the Impact of Early-Time Operations • Williams-Kovacs

1.  Unconventional Reservoir Analysis Workflow 2.  Conceptual Model of Flowback and Analysis Procedure 3.  Case Study: Tight Oil Well

Ø  Commingled Flowback Ø  Microseismic Ø  Frac Modelling Ø  Online Production Data Analysis

4.  Key Takeaways 5.  Discussion Points 6.  Flowback Data Gathering and Assessment 7.  Impact of HC Breakthrough and Shut-Ins During Flowback


UNCONVENTIONAL RESERVOIR ANALYSIS

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UNCONVENTIONAL RESERVOIR ANALYSIS


Pre-‐Drill Reservoir Sample and Log Analysis

Pre-‐Frac Welltest and DFIT Analysis

Fracture Monitoring (microseismic, etc.)

Pre-‐Frac

Frac Treatment

Post-‐Frac Frac ModellingFlowback Analysis, Post-‐Frac Well Test

Online Production Data Analysis Reservoir Simulation (analytical and numerical)Rate-‐Transient Analysis

Well Optimization

Economic AssessmentEconomic Analysis

Future Development Planning

Absolute permeability, porosity, pore size distribution, capillary pressure and relative permeability, electrical properties, fluid saturation, TOC, gas content, adsorption isotherm, rock mechanical properties

kh, initial reservoir pressure

Frac performance, maximum half-‐length, maximum SRV

xf, kf, FCD, Acm

kh, xf, FCD, Acm, History-‐match and forecast future production

NGL yields, economic indicators

Optimize future well performance

Additional Data: fluid properties, flowing pressures, seismic, spinner & tracer logs, completion data, wellbore diagram, deviation survey


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CONCEPTUAL MODEL OF FLOWBACK


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CONCEPTUAL MODEL OF FLOWBACK


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CONCEPTUAL MODEL OF FLOWBACK - OIL


Deterministic Match·∙ Manual or Assisted·∙ First Pass Estimate

of Match Properties·∙ Assess Model

Applicability and Select Fracture Geometry

Stochastic Match #1·∙ All Uncertain

Properties Set as Distributions

·∙ Assess Combinations of Properties Which Can Match

·∙ Assess Uniqueness of Deterministic Match

Stochastic Match #2·∙ Reduce Number of

Inputs and Ranges·∙ Develop Distributions

for Fit Cases

Stochastic Output·∙ Distributions of

Matching Parameters and Forecasts

Diagnostic Plots and Rate-Transient Analysis·∙ Assess data quality·∙ Identify flow-regimes

present·∙ Analyze pre-BT flow

regimes using single-phase methods

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ANALYSIS PROCEDURE

•  PDA methods used in Flowback: 1.  Analytical Simulation

Ø  Can be used to estimate fracture drainage area/volume and other parameters before and after hydrocarbon breakthrough

2.  RTA and Type-Curves Ø  Estimate key hydraulic fracture properties using single-phase BBT

data §  Fracture conductivity §  Half-length

•  Analysis Procedure:

•  Tight oil reservoir in the WCSB (NE BC)

•  Cased hole completion

•  Hydraulically fractured with hybrid water fracs in 18 stages

•  Frac stages spaced at ~ 110 ft

•  1,350 STB of frac fluid and 45 T pumped per stage

•  Microseismic suggests circular fractures with bi-wing planar geometry – Frac Geometry #1

CASE STUDY – OVERVIEW

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Water RNP Derivative Plot Water RNP Derivative Plot

CASE STUDY – RAW DATA AND DIAGNOSTICS

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Unit slope shown for reference – indicated fracture depletion


CASE STUDY – RATE TRANSIENT ANALYSIS

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Minimal radial flow data available for analysis

Deviation resulting from breakthrough of formation fluid



CASE STUDY – DETERMINISTIC HISTORY-MATCH

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•  Good match of water, oil and gas rate prior to gas breakthrough (~8 days)

•  Significant uncertainty in analysis due to number of parameters being adjusted to achieve history-match (i.e. xf, fracture permeability, thickness, etc.)

Gas breakthrough into the fractures – oil and water rate over-predicted after this point

Cum

Gas

Pro

d (M

SCF)

CASE STUDY – PARAMETER DISTRIBUTIONS

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Multi-phase flowback data CAN be quantitatively analyzed to estimate key

“effective flowing” frac properties





Pre-‐Frac

Frac Treatment



Well Optimization






xf, kf, FCD, Acm





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CASE STUDY – COMPARISON WITH OTHER DATA

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From Barree et al., 2014 SPE Production & Operations (SPE 169539)

From pseudo-radial flow km = 300 nd






Pre-‐Frac

Frac Treatment



Well Optimization






xf, kf, FCD, Acm





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Frac Treatment: Microseismic Fracture Mapping

Vertical Observation Array

Horizontal Observation Array

Significant Frac Height Growth

Planar Fracture Geometry Created xf ~ 890ft/stage





Pre-‐Frac

Frac Treatment



Well Optimization






xf, kf, FCD, Acm





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Post-Frac: Frac Modelling

xf ~ 295ft/stage

xf ~ 492ft/stage

Propped xf ~ 300-500ft/stage





Pre-‐Frac

Frac Treatment



Well Optimization






xf, kf, FCD, Acm





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0.0E+00

2.0E+01

4.0E+01

6.0E+01

8.0E+01

1.0E+02

1.2E+02

1.4E+02

1.6E+02

1.8E+02

2.0E+02

0 5 10 15

[pi-p

wf)/

qo

Sqrt Time (Days)^0.5

Square-Root Time Plot Linear Flow Analysis

Raw Data Raw Data Corrected For Multi-Phase Flow Fit


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Online PDA: Rate Transient Analysis

Uncorrected Analysis xf ~ 70ft/stage

Effective Online xf ~ 105ft/stage

Corrected Multi-Phase Analysis (SPE 167176)

xf ~ 105ft/stage





Pre-‐Frac

Frac Treatment



Well Optimization






xf, kf, FCD, Acm





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Online PDA: Numerical Modelling

1

10

100

1000

1

10

100

1000

0 50 100 150 200 250 Time (days)

Gas

Rat

e (M

scf/d

)

Oil

Rat

e (S

TB/d

)

Online Production History-Match

qo_data qo_match qg_data qg_match

Effective Online xf ~ 105 ft/stage


CASE STUDY – SUMMARY OF RESULTS

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Frac Half-Length (ft/stage)

Microseismic 890

Frac Modelling 300-500

Flowback (Before Breakthrough) 420

Flowback (After Breakthrough) 380

Online Rate Transient Analysis 105

Online Numerical Simulation 105

Frac Treatment

Post-Frac

Online PDA

“Created” xf

“Propped” xf

“Effective Flowing” xf

“Effective Online” xf

“Created” xf 890 ft

“Propped” xf 300-500 ft

“Flowing” xf 380 ft

“Online” xf 105 ft



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Microseismic 890






“Created” xf

“Propped” xf



Reduction in estimated half-length throughout well life

“Created” xf 890 ft

“Propped” xf 300-500 ft

“Flowing” xf 380 ft

“Online” xf 105 ft



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Frac Treatment

Post-Frac

Online PDA

“Created” xf

“Propped” xf



1

10

100

1000

10000

0 100 200 300 400 500 600

Oil

Rat

e (S

TB/D

)

Cum Oil Produced (MSTB)

Comparison of Rate Profiles For Different Half-Lengths (20 Year Forecast)

Created xf Propped xf Flowing xf Online xf

Declining Performance with Half-Length

Calibrated Model Assuming Constant Flowing Pressure and No Contribution From Beyond SRV



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Frac Treatment

Post-Frac

Online PDA

“Created” xf

“Propped” xf



$11,630

$2,550 $2,170

-$3,370

124%

25% 22%

N/A

-50%

0%

50%

100%

150%

$(5,000)

$-

$5,000

$10,000

$15,000

NPV10 ($M)

IRR (%) NPV10 ($M)

IRR (%) NPV10 ($M)

IRR (%) NPV10 ($M)

IRR (%)

Created xf Propped xf Flowing xf Online xf

IRR

(%)

NPV

10 ($

M)

Comparison of NPV10 and IRR For Different Half-Lengths (20 Year Forecast)

Declining Economic Performance with Half-Length – Online xf Only Uneconomic Outcome!

Total CAPEX: $5.6MM Commodity Price: Oil - $65/bbl; Gas - $3.00/MMBtu


Mechanisms for evolution of frac properties over time: 1.  Flowing below bubble point mobilizes gas in the fractures leading to three-phase

flow and loss of effective permeability (downhole gas separation may be beneficial) 2.  High drawdowns lead to loss of fracture conductivity and closure of secondary

fractures – higher effective stress (intelligently control drawdown) 3.  Crushing/flowback of proppant (high strength, resin coated may be beneficial) 4.  Insufficient proppant pumped for frac height and half-length created 5.  Gravity segregation 6.  Analysis assumptions 7.  Other reasons?

Operational


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Microseismic 890






“Created” xf

“Propped” xf



Reduction in estimated half-length throughout well life

ü  Reservoir characterization techniques should be integrated to understand the reservoir

ü  Multi-phase flowback data can be quantitatively analyzed to estimate “effective flowing” frac properties

ü  Evolution of frac properties over the well life Ø  Both flowback and long-term operations can effect frac properties and

impact long-term production

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KEY TAKEAWAYS


Acknowledgements / Thank You / Questions / Discussion Points Jesse Williams-Kovacs would like to thank the University of Calgary, TAQA North

Ltd. AND Dr. Christopher Clarkson at the University of Calgary

Discussion Points: 1.  Methods and benefits of collecting stage-by-stage flowback data 2.  Tight gas and shale gas flowback assessment 3.  Impact of fracture shape 4.  Methods for estimating hydraulic fracture compressibility

Reference Material: 1.  Shale Gas: SPE 162593, SPE 164550, URTeC 2149183 (URTeC 2015) 2.  Tight Gas Condensate: SPE 167231 3.  Tight Oil: SPE 166214, SPE 167232 4.  Multi-well Flowback: SPE 171591 5.  Tight Oil Case Study: The Leading EDGE , October 2014

CANADIAN BUSINESS CONFERENCES ARTIFICIAL LIFT & HORIZONTAL PRODUCTION COST REDUCTION INITIATIVE 2015 29-30 APRIL 2015 • CALGARY, ALBERTA


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FLOWBACK DATA GATHERING AND ASSESSMENT


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FLOWBACK DATA GATHERING AND ASSESSMENT

Data Gathering

Flowback Specific:1) High-‐frequency rates and flowing pressures (hourly or more frequent – every 15-‐30 minutes desirable)2) Initial fracture pressure (frac modelling, other estimate – typically 20-‐50% greater than Pi)3) Indication of fracture geometry (microseismic, frac modelling, experience, etc.)

Optional:1) Method to allocate data to individual stages (i.e. spinner & tracer logs, fibre-‐optic techniques) 2) Sandface flowing pressures (downhole gauges)3) Salinity of frac fluid4) Estimate of fracture relative permeability curves (lab experiments)

Diagnostics

Quantitative Assessement

Other:1) Wellbore schematic, deviation survey and stimulation information 2) Fluid properties (oil, water and gas analysis)3) Formation temperature4) Estimate of initial reservoir pressure and matrix permeability (DFIT, pre-‐frac welltest, core)5) Estimates of net pay, porosity and fluid saturation (logs and core)

Optional:1) Detailed PVT analysis2) Estimate of matrix relative permeability curves (lab experiments)3) Offset well analysis

Base Plots:1) qw, qo and qg vs. t (stage-‐by-‐stage if available)2) Flowing pressure (surface, downhole or converted) and choke setting vs. t

Primary Diagnostic Plots:1) RNP vs. t or tca (water typically most diagnostic)2) RNP Derivative vs. t or tca (water typically most diagnostic)3) GWR vs. Gp (gas specific)

Other Diagnostic Plots:1) RNP vs. cumulative production (all phases)2) pcf vs. qw, qo and qg3) Gp or Np vs. Wp

Hydraulic Fracture Property Determination and Forecast:1) Rate-‐transient analysis (radial flow analysis, flowing material balance, Fetkovich type curve)2) Analytical simulation (history-‐match)3) Forecast long-‐term production


CASE STUDY – STOCHASTIC HISTORY-MATCH

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CASE STUDY – STOCHASTIC HISTORY-MATCH


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CASE STUDY – PARAMETER DISTRIBUTIONS

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IMPACT OF HC BREAKTHROUGH AND SHUT-INS

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Single-phase flow

Gas Break-through reduces xf,eff

Shut-in reduces xf,eff

Example From SPE 119894

Tight Gas

Shut-in reduces xf,eff

Tight Gas Condensate

a)

Gas Break-through reduces xf,eff

Oil Break-through reduces xf,eff

Tight Oil

b)

c)

d)

IMPACT OF HC BREAKTHROUGH AND SHUT-INS

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Flowback operations impact long-term productivity

Documents

Assessing Multiple Data Sources to Understand Frac ... UNCONVENTIONAL RESERVOIR ANALYSIS Assessing the Impact of Early-Time Operations • Williams-Kovacs Pre$Drill Reservoir(Sample(and(Log(Analysis