1. The SPE Foundation through member donations
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

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

3. The Unconventional Resource Revolution in North America
Technology enabled production from unconventional reservoirs
Horizontal drilling increased reservoir contact area
Hydraulic fracturing enhanced very low permeability
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
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?
Technically Recoverable Shale Resources
Key Factors for Success
Operational Execution
Technical Understanding
Strategic Development Plan
Source: EIA, Aug 2016

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

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

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

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

9. Fluid Properties- Reservoir Characterization
Black Oil and Volatile Oil System
Gas Condensate System
3,000
14,000
12,000
6,000
5,000
GOR=4,000
2,400
2,000
Conventional
1,000
Increased Compressibility
Increased Recovery with
Pressure, psia
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
Increased Recovery with
Decreased Viscosity
GOR=700
Temperature, ˚F
Temperature, ˚F

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

11. Formation Deliverability- Reservoir Characterization
Gamma Ray (GAPI)
Lodgepole
Lower
Bakken
Upper Bakken
Middle Bakken
Scallion
Three Forks
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: md
Pressure: psi
Kurtoglu et al., 2013 (SPE )

12. Geomechanical Properties- Reservoir Characterization
Diagnostic Fracture Injection Test
Fracture Properties
Microseismic
Reservoir Connectivity
Proppant placement
using down-hole ≈ ft
Derivative
Pressure (psi)
Horizontal Connectivity
Superposition Derivative
G-Function
Target Zone
Upper Formation
Lower Formation
Formation leak-off mechanism
Fracture closure pressure
Pore pressure
Vertical and horizontal connectivity
Vertical Connectivity
Kurtoglu et al., 2012 (SPE )

13. Well Life Cycle- Operational Execution1 2 3 4
Completion
Flowback
Production
Refrac/ Gas Injection
Gas
Production Time
Oil
Water
1 mile
Normalized Cumulative MBOE
%25
Produced Days
Development Acreage

14. Completion Efficiency- Operational Execution
Slurry Rate
400’
400’ Stage Spacing
Stimulated Reservoir Volume
250’
250’ Stage Spacing
Fracture Treatment Pressure along the Lateral
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’ Stage Spacing
250’ Stage Spacing
Decreased Fracture Initiation
Average Treatment
Pressure (psi)
Stage Number
Kurtoglu et al., 2015 (SPE )

15. Hourly Flowback- Operational Execution Bilinear Flow Analysis
Multi-Phase Flowback
Bilinear Flow Analysis
Hydrocarbon
Water
400’ Stage Spacing
250’ Stage Spacing
Hydraulic Fracture Conductivity
Reservoir Effective Permeability
Bilinear Slope
Increased fracture conductivity
Increased reservoir connectivity
mBL
Rate Normalized Pressure
Δp/qt (psi/BBL/D)
Bilinear Flow: One linear flow within fracture towards well and one within the formation towards the fracture
Time1/4 (days1/4)
Kurtoglu et al., 2015 (SPE )

16. Daily Production- Operational Execution Multi-Phase Production
Linear Flow Analysis
Hydrocarbon
Water
400’ Stage Spacing
250’ Stage Spacing
Linear Slope
Increased reservoir connectivity
Reservoir Effective Permeability
Fracture
Half-
Length
Increased SRV mL
Rate Normalized Pressure
Δp/qt (psi/BBL/D)
Linear Flow: Linear flow within stimulated reservoir volume (SRV) towards well
Time1/2 (days1/2)
Kurtoglu et al., 2015 (SPE )

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

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

19. Well-to-Well Interaction- Value Creation
Development Acreage
Negative Frac Interference
Reduced SRV
Frac Hit
Rate Normalized Pressure
Δp/qt (psi/BBL/D)
Linear Flow
Geological
Risk
High Risk
Low Risk
1 mile
Positive 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
Time1/2 (days1/2)
Reduced SRV
Increased SRV
Frac Hit
Rate Normalized Pressure
Δp/qt (psi/BBL/D)
Linear Flow
Kurtoglu et al., 2015 (SPE )
Time1/2 (days1/2)

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

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

22. Enhanced Recovery- Design Consideration
Target Fluid Window 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
Eagle Ford Gas-Oil Ratio
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
Sub-optimum Areas due to Structural Features for EOR
Bakken Structure

23. Enhanced Recovery- Design Consideration
Bakken Water Huff & Puff
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 ( present)
Bakken Huff & Puff CO2 Injection
Eagle Ford Huff & Puff Gas Injection
Finding cost <$6 per bbl
Capital investment ~$ 1MM per well
Long reserve life and low decline rate
Source: SPE , 2016
Source: EOG Investor Presentation, May 2016 14

24. Development Scenarios
Value Realization
Development Scenarios
Well Count
EUR/Well
(Mbbl)
Reserve (Mmbbl)
Base Case 40
456 18
Upside Case
160
637
102
1 mile
Development Acreage
EUR Evolution
Base Case
1- spud to spud: 30 day
2-spud to frac: 120 day for 4 well pad
3- type curve includes completion upside
Upside Blue Case
1- spud to spud: 17 day
2- spud to frac: 80 day for 4 well pad
3- type curve all in
4- EOR starts in 2020
Green Upside Case
1- soud to spud: 60 day
2- spud tp frac: 120 day for 4 well pad
4- EOR starts in 2030
I’ve taken you on a journey from the base line valuation of unconventional reservoirs and we’ve now arrived at the true value proposition by incorporating the technical justification of multi-horizon development, selecting the best target, identifying the best completion strategy, finding the right well spacing and finally enriching the portfolio with enhanced recovery techniques to arrive at the true value proposition.
On a single well bases, we’ve gone from 456 MBOE and arrived at the full potential of 637 MBOE.
When we roll up the entire acreage position, we’ve not only increase per well recoveries, but we’ve increased the well counts, yielding a full project reserve recovery going from 18 MMBOE to 102 MMBOE…
Increased recoveries are all well and good, but can we realize economic value with these improvements?
He talked about:
Highest DD&A
Lowest cost to find oil
Value enhancement
Optimization yields better results
Increasing NPV through technical , execution, and decision
The answer is yes. Comparing the base case that consisted of a completion design of 350’ stage spacing, 600 lb/ft and 80 acre well spacing for 40 wells and a total investment of $251MM, we realize an NPV10 of ____ yielding an acreage value of $26,000/acre. By employing the technically justifiable improvements to the most hated, black oil acreage, we’ve improved our completion design to 250’ stage spacing, 1,200 lb/ft and 40 acre well spacing…with a total well count of 160 wells and an investment of $1.5 B, we can now realize and NPV10 of $355 MM, improving our value to a much more favorable $111,000/acre…
Reserve Add

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

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

27. Developing Unconventionals Worldwide
Source: EIA

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