In this lecture, the experience from U.S development is utilized to provide a fully-integrated workflow for developing shale oil and gas reservoirs from exploitation to production.

1. Primary funding is provided by
The SPE Foundation through member donations
and a contribution from Offshore Europe
The Society is grateful to those companies that allow their
professionals to serve as lecturers
Additional support provided by AIME
Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl

2. Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl 2
Basak Kurtoglu, PhD
Citi Global Energy Group
Creating a Worldwide
Unconventional Revolution
Through Technically Justifiable Strategies

3. The Unconventional Resource Revolution
in North America
3
 Technology enabled
production from unconventional
reservoirs
‒ Horizontal drilling increased
reservoir contact area
‒ Hydraulic fracturing enhanced
very low permeability
 2000-2010 Highlights:
‒ All started with the Barnett in
Texas
‒ Development of Bakken in
Montana shifted to North
Dakota
‒ The Marcellus started to
develop in Pennsylvania and
West Virginia
‒ Activity in the Haynesville
started in eastern
Texas/western Louisiana
Basin
Shale
Prospective
Shallow
Intermediate
Deep
US Unconventional Play Development
 2010- 2015 Highlights
‒ Eagle Ford became the lead for oil production
‒ Permian has received great attention with multi-horizon
development opportunities
‒ Unconventional development propelled the United States to
produce more oil than it imports for the first time in 20 years

4. How to Develop Unconventionals Worldwide?
4Source: EIA, Aug 2016
Key Factors for Success
 Operational Execution
 Technical Understanding
 Strategic Development Plan
Technically Recoverable Shale Resources
0
500
1000
1500
GAS(TCF)
Shale Gas
0
10
20
30
40
50
60
70
80
OIL(BILLIONBBL)
Shale Oil

5. 5
Reservoir Characterization
Operational Execution
Value Creation
Integrated Workflow
 Petroleum system
 Targeting and landing
 Multi-horizon development
 Completion design
 Well spacing
 Improved/Enhanced recovery
Development Strategy
Unconventional Approach

6. 6
Source Rock Properties- Reservoir Characterization
TOC: 2- 4 weight %
kmarl: 5.0E-07 md
TOC: 25- 28 weight %
kshale: 4.0E-08 md
 Pore structure-
Scanning Electron
Microscopy (SEM)
 Maturity- Total Organic
Carbon (TOC)
 Ductility
 Low permeability (k)
Bakken (Locally Sourced)
Kurtoglu, 2013 & Rosen et al., 2014 (SPE 168965) 6
1 mile
Appraisal Phase
Eagle Ford (Self-Sourced)
Black Shale SEM
Marl SEM
Development Acreage

7. 7
 Pore structure-
Scanning Electron
Microscopy (SEM)
 Micro-fractures
 Brittleness
 High permeability (k)
kfractured- core: 0.0013 md
kfractured- core: 0.0059 md
Kurtoglu et al., 2014 (SPE 171688) & Rosen et al., 2014 (SPE 168965)
Bakken- Thin Section
Eagle Ford- Thin Section
500 μm
500 μm
Sandstone SEM
Limestone SEM1 mile
Appraisal Phase
Development Acreage
Reservoir Rock Properties- Characterization

8. 8
Target Window- Reservoir CharacterizationCurrentConventional
Strategy
Storage Capacity
Energy/Drive
Thickness and extent
Porosity: type and amount
Fluid(s): type and amount
Pore pressure & GOR
Burial history
Seals
Connectivity
Brittleness of the rock
Faults and natural fractures
Type and amount of clay
Ability to induce fractures
Ability to maintain fractures
Unconventional
Strategy
Source Rock %: 70
Reservoir Rock %: 30
Frequency: 1/10ft
Source Rock %: 70
Reservoir Rock %: 30
Frequency: 3/10ft
Increased Interbedding= Increased Connectivity
LOW HIGH
1ft
Reservoir Rock: Brittle
Source Rock: Ductile

9. 9
Fluid Properties- Reservoir Characterization
Black Oil and Volatile Oil System
IncreasedRecoverywith
DecreasedViscosity
1,000
2,000
2,400
3,000
14,000
12,000
6,000
5,000
GOR=4,000
GOR=700
Gas Condensate System
IncreasedRecoverywith
IncreasedCompressibility
 Increased capillary pressure
 Bubble point suppression
 Delayed multi-phase production
 Longer time constant gas-oil ratio (GOR)
 Lesser volume of gas released below
bubble point pressure
Unconventional
Nano pore
Conventional
Temperature, ˚F Temperature, ˚F
Pressure,psia

10. 10
Rock-Fluid Interaction- Reservoir Characterization
Kurtoglu et al., 2014 (SPE 171688) & Fakcharoenphol et al., 2014 (SPE 168998)
Transport Processes
 Counter-current spontaneous imbibition
 High and Low Salinity
 Osmotic pressure
 Wettability
2- Low Salinity Experiment
after 5 days
Bakken Reservoir Rock
1- High Salinity Experiment

11. 11
Formation Deliverability- Reservoir Characterization
Kurtoglu et al., 2013 (SPE 162921)
 Core to field level permeability reconciliation
 Near wellbore transient behavior:
 Mini- Drill Stem Test (DST)
 Target zone identification
 Formation deliverability and pressure
Laminated zone
Permeability: 0.013 md
Pressure: 6354 psi
Gamma Ray (GAPI)
Lodgepole
Lower
Bakken
Upper
Bakken
Middle
Bakken
Scallion
Three
Forks

12. 12
Kurtoglu et al., 2012 (SPE 162473)
 Formation leak-off
mechanism
 Fracture closure pressure
 Pore pressure
 Vertical and horizontal
connectivity
0 10 20
G-function
7000
7500
8000
Pressure[psi]
0
1250
2500
Pressure[psi]
0
250
500
Pressure[psi]
P (ref)
dP/dG (ref)
G.dP/dG (ref)
G-Function plot
G-Function
SuperpositionDerivative
Pressure(psi)
Derivative
Geomechanical Properties- Reservoir Characterization
Diagnostic Fracture Injection Test
Fracture Properties
Microseismic
Reservoir Connectivity
Proppant placement
using down-hole ≈ 150-200 ft
HorizontalConnectivityVerticalConnectivity
Target Zone
Upper Formation
Lower Formation

13. 13
Well Life Cycle- Operational Execution
1 2 3 4
Completion Flowback Production Refrac/ Gas Injection
Gas
Production Time
Oil
Water
1 mile
NormalizedCumulativeMBOE
%25
Produced Days
Development Acreage

14. 14
Completion Efficiency- Operational Execution
Fracture Treatment Pressure along the Lateral
AverageTreatment
Pressure(psi)
250’
Stage
Spacing
Stage Number
Decreased
Fracture
Initiation
 Design parameters
 Stage/cluster spacing
 Proppant type/volume
 Frac fluid type/volume
 Injection rate/pressure
 Creation of stimulated
reservoir volume
 Fracture network
complexity and
propagation
400’
250’
400’
Stage
Spacing
Slurry Rate
Kurtoglu et al., 2015 (SPE 172922)
Stimulated
Reservoir
Volume
400’ Stage Spacing
250’ Stage Spacing

15. 15
Multi-Phase Flowback Bilinear Flow Analysis
Time1/4 (days1/4)
41
1
102.44










efft
t
fff
t
BL
kcwkhn
m


Hydrocarbon
Water
Bilinear Flow: One linear flow within
fracture towards well and one within
the formation towards the fracture
md/cp-
1/psi-
md-
ft-idth
md-
stages
ft-
mobilitytotal
ilitycompressibtotalc
porosity
typermeabilieffectivek
wfracturehydraulicw
typermeabilifracturehydraulick
ofnumbern
thicknessh
t
t
eff
f
f
f










400’ Stage Spacing
250’ Stage Spacing
Hourly Flowback- Operational Execution
Kurtoglu et al., 2015 (SPE 172922)
RateNormalizedPressure
Δp/qt(psi/BBL/D)
Hydraulic
Fracture
Conductivity
Reservoir
Effective
Permeability
Bilinear
Slope
Increased
fracture
conductivity
Increased
reservoir
connectivity
mBL

16. 16
Daily Production- Operational Execution
Multi-Phase Production Linear Flow Analysis
Linear Flow: Linear flow within
stimulated reservoir volume
(SRV) towards well
Hydrocarbon
Water







tteffff
L
ckxhn
m

191.19
Time1/2 (days1/2)
md/cp-
1/psi-
md-
ft-
stages
ft-
mobilitytotal
ilitycompressibtotalc
porosity
typermeabilieffectivek
hhalf-lengtfracturex
ofnumbern
thicknessh
t
t
eff
f
f









400’ Stage Spacing
250’ Stage Spacing
Kurtoglu et al., 2015 (SPE 172922)
RateNormalizedPressure
Δp/qt(psi/BBL/D)
Linear
Slope
Increased
reservoir
connectivity
Reservoir
Effective
Permeability
Fracture
Half-
Length
Increased
SRV
mL

17. 17
Geological Impact- Operational Execution
Key Attributes
 Pore Pressure
 Thickness
 Porosity
 Water Saturation
 Fault/Structure
 Fracture Intensity
CumulativeOilProduction(BBLS)
Time (days)
Good Geology
SRV: 28 acre
Time1/4 (days1/4)
Poor Geology
SRV: 13 acre
RateNormalizedPressure
Δp/qt(psi/BBL/D)
Well in Sweet Spot area
Well in Poor Geological Area
1 mile
Development Acreage
High
Risk
Low
Risk
Geological
Risk

18. 18
Well Spacing- Value Creation
 Defining boundaries of
reservoir both vertically
and horizontally
 Simulation of scenarios
 Determine point of
diminishing return
 Validation with field results
NetPresentValue($M)
Well Count/Spacing Unit
CumulativeOil(BBLS)
Reservoir Modeling for Well Spacing
80 acre: 3 well/unit
40 acre: 6 well/unit
60 acre: 4 well/unit
Time (days)
Increased Well
Interference
80 acre: 3 well/unit
40 acre: 6 well/unit
60 acre: 4 well/unit
Time (days)
CumulativeOil(BBLS)
Time (days)
CumulativeOil(BBLS)
Actual 40 acre well
80 acre: 3 well/unit
40 acre: 6 well/unit
60 acre: 4 well/unit
1 mile
Development Acreage
High
Risk
Low
Risk
Geological
Risk

19. Time1/2 (days1/2)
Well-to-Well Interaction- Value Creation
Negative Frac Interference
Hydraulic Fracture Interference
 Overlooked risk during infill
development
 Awareness of dynamic alteration
of reservoir
 Positive or negative impact on
existing production
 Incorporate into plan of
development
Kurtoglu et al., 2015 (SPE 172922)
1 mile
Development Acreage
Reduced
SRV
Frac Hit
RateNormalizedPressure
Δp/qt(psi/BBL/D)
Linear Flow
High
Risk
Low
Risk
Geological
Risk
Time1/2 (days1/2)
Reduced
SRV
Increased
SRV
Frac Hit
RateNormalizedPressure
Δp/qt(psi/BBL/D)
Linear Flow
Positive Frac Interference

20. 20
Refrac- Value Creation
 Application of learnings from
frac interference
 Classifying opportunities for
refrac based on:
 Increased productivity
 Altered fluid mobility
 Poor initial completion
Time (days)
Oil rate
increase of
1210 bbl/d
Time1/2 (days1/2)
Δ(86psi/bb/dl)
RateNormalizedPressure
Δp/qt(psi/BBL/D)
OilRate(BBL/D)
WaterRate(BBL/D)
Refrac
86 psi/bbl/d
productivity
increase
Refrac
Kurtoglu et al., 2015 (SPE 172922)
1 mile
High
Risk
Low
Risk
Development Acreage
Geological
Risk

21. 21
Enhanced Recovery- Value Creation
Build
Integrated
Reservoir
Model to
Understand
Physics
Select the Best
Location & Design
Field Application
Characterize
Nano-Pore Rock
and Fluid
Properties
Permeability Distribution
RateNormalizedPressure
(psi/BBL/D)
Time1/2 (days1/2)
Nano-pore
Gas
Injector
Rock Properties
Fluid Properties
Oil Rate (Eagle Ford)
1 mile
Unconventional
Nano pore
Conventional
Primary Development
High
Risk
Low
Risk
Low pressure area
High pressure area
Enhanced Recovery
Less
Potential
More
Potential
Source: EOG, May 2016

22. 22
Enhanced Recovery- Design Consideration
Design
Considerations
Objective
Reservoir Fluid
Target thermally less
matured areas
Fracture Network
Map fracture pathways and
control horizontal
containment
Well Spacing Prevent early breakthrough
Wellbore
Configuration
Compatible casing design to
high pressure limits
Multi-horizon
Development
Less well interference for
vertical containment
EOR Fluid Selection
Injected gas availability
Midstream infrastructure
Compatible Well
Completion
Re-entry to the wellbore for
injection
Target Fluid Window for EOR
Elm Coulee
Parshall – Sanish
- Reunion Bay
Bailey –
Murphy Creek
Antelope
Field
MONTANA
NORTH
DAKOTA
Eagle Ford Gas-Oil Ratio
Bakken Structure
Sub-optimum Areas due to Structural Features for EOR
EOR design should be planned early in the
primary development so that wells are
drilled and completed in a way that is
compatible with the future EOR application

23. 23
Enhanced Recovery- Design Consideration
 There has been an increased interest and field
trials in unconventional plays since 2008
 North Dakota Bakken: CO2 Huff & Puff (2008),
Water Huff & Puff (2012), Water Flood (2014),
Natural Gas Flood (2014)
 Montana Bakken: CO2 Huff & Puff (2009) and
Water Flood (2014)
 Eagle Ford: Natural Gas Huff & Puff (2014-
present)
Bakken Water Huff & Puff
Eagle Ford Huff & Puff Gas InjectionBakken Huff & Puff CO2 Injection
Source: SPE 180270, 2016 Source: EOG Investor Presentation, May 2016
 Finding cost <$6 per bbl
 Capital investment ~$ 1MM per well
 Long reserve life and low decline rate

24. Value Realization
24
Development
Scenarios
Well Count
EUR/Well
(Mbbl)
Reserve
(Mmbbl)
Base Case 40 456 18
Upside Case 160 637 102EUREvolutionReserveAdd

25. CAPEX($MM)
Business Impact
25
Project Review
Base Case
Primary Development
Upside Case
Tertiary Development
Completion
Stage spacing (ft) 350 250
Proppant loading (lb/ft) 600 1,500+
Well spacing 80 40
Well Count 40 160
Net CAPEX ($MM) 243 1,496
Net Reserves (MMBOE) 16 90
NPV10 ($MM) 83 357
ROR (%) 28 30
Discounted NPV10/I 0.42 0.42
NPV10/Acre ($/acre) 26,000 111,000
Primary- Base Case
Primary- Upside Case
Tertiary- Upside Case
Without EOR
EOR started
DailyRate(BOPD)
68,000

26. 26
Conclusions
 Petroleum System
 Stratigraphic Variations
 Fluid Properties
 Formation Deliverability
 Geomechanical Properties
Reservoir
Characterization
Operational
Execution
Value
Creation
Creating a Worldwide Unconventional Revolution
 Completion
 Flowback
 Production
 Geology
 Well Spacing
 Well to Well Interaction
 Refrac
 Enhanced Oil Recovery

27. Developing Unconventionals Worldwide
27
Source: EIA

28. Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl 28
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