Bakken Reservoir and Operations
Optimization
North Dakota Petroleum Council 2013 Annual Meeting
Grand Forks, North Dakota
September 18, 2013
John Harju
Stan Wilson
Associate Director for Research
Manager, Resource Development
Energy & Environmental Research Center
Continental Resources, Inc.
© 2013 University of North Dakota Energy & Environmental Research Center.
Program Partners
The International Center for Applied Energy Technology ®
Presentation Overview
• Key Bakken and Three
Forks Issues
• Bakken Optimization
Program Goals
• Program Focus Areas
– Downhole
– Wellsite Operations
• Example Project
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Why Optimization Is Important…
• World-class resource
• Currently, only 3%–
10% recovery factor.
• A 1% increase
translates to as much
as 9 billion barrels of
recovered oil
(or more).
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Bakken Petroleum System Total Oil in
Place Reserve Estimates
We Need a Paradigm Shift
• Issues related to oil and gas development should not be
the sole responsibility of industry.
• EVERYONE benefits from (relatively) inexpensive,
abundant supplies of oil and gas.
• Optimizing production of this resource benefits everyone
– let’s tackle it collectively.
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Current Downhole Hurdles
• Incomplete understanding of the resource, its potential,
and how to best extract the oil with current technology.
– Optimal well spacing?
– Communication between formations/benches?
– Identification of sweet spots.
– Influence of fracture networks?
– Optimal completion and
stimulation techniques?
– How to best expand the
run life of downhole
production
equipment.
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Current Operational Hurdles
• Flaring and associated gas collection
(and utilization).
• Solid waste management.
• Water minimization, recycling, and
reuse.
• Other issues, such as truck traffic, dust,
road maintenance, and air emissions.
• Many “issues” are driven by public
perception and/or misconception.
• Some of the challenges are a result of
regulatory requirements, such as pitless
drilling.
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Benefits of Optimization
Production Optimization
– Increases revenue to industry and the state (and
associated benefits to residents).
– Facilitates continued
investment of the oil and
gas industry into the oil
and gas resources of the
region.
– Assures conservation by
optimizing the efficient
and effective recovery of
the oil and gas resource.
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Image: Popular Mechanics
Benefits of Optimization
Wellsite Operation Optimization
– Reduce costs and improve efficiency.
– Reduce development and operation impacts to
surrounding landowners.
– Reduce demands on surrounding infrastructure and
water sources.
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Industry and the State Are Making
Progress…
• Improved drilling practices
• Multiwell pads, reduced surface impacts
• More advanced completion techniques (multistage
fractures, improved proppants and fluid systems)
• Improved characterization and understanding of the
resource and fracture networks
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Industry and the State Are Making
Progress…
• Improved gas pipeline networks.
• Increased collection and utilization
of associated gas (bifuel engines,
natural gas liquid [NGL] extraction,
compression, and use).
• Improved solid waste
management and strategies for
beneficial reuse.
• Increased focus with the state to
address issues and develop sound
and sustainable solutions.
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Image: The Bakken Magazine
Program Goals
To facilitate ongoing efforts by industry and the state to
optimize Bakken/Three Forks production:
– Advanced reservoir characterization and more accurate
resource estimates.
– Improved drilling/stimulation/completion/production
techniques and sequences.
– Optimization of
wellsite surface
operations and
reduced surface
impacts.
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Image: http://blogs/calgaryherald.com
Key Roles
• EERC
– Optimization of wellsite operations
– Work with program partners to implement viable options
– Dissemination of program activities and results, reporting
• Continental
– Improved characterization of the Three Forks reservoir
– Evaluation of fracture patterns and sweet spots
– Design more effective completion and production strategies
• Current and Future Partners
– Help steer program activities and priorities
– Provide real-world advice and experience
– Relay program findings internally
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Production Optimization:
Hawkinson Project
Bakken Petroleum System Redefined
Lodgepole
Upper Shale
Middle Bakken
Lower Shale
Three Forks 1
TF2
TF3
TF4
Nisku
Charlotte 1-22H core photos
(UV light)
308’ with 154’ of oil
fluorescence
Past: Dual Reservoir Development
MB and TF wells on 320 acre spacing
Lodgepole
10,000’
below
surface
Upper Bakken
shale
1,320
’
Middle Bakken
Lower Bakken
shale
Three Forks
660’ 660’
Multiple fracture stages
1,320
’
Dual Zone TestsTests
Medicine Hole 14-27H and 2-27H wells
Dunn Co., North Dakota
Conclusion from Dual Zone Tests
Neither zone can be adequately drained by completion in
another zone
Limited connectivity will require wells in both zones to
adequately harvest the reserves
Reserves from MB and TF are similar in magnitude
CLR: Deep Three Forks Development
Three Forks Isopach Map
10-well coring program
(2012)
Barney 2-29-H
320
TF
2,3,4
Lower TF exploration net
capex 2013
TF
2,3
Angus 2-9H-2
2,107 Boepd
TF
2,3
TF
2
160
 Productivity Project
• Exploratory and appraisal:
 Pilot Density Projects
• Three 320-acre density tests:
$161MM net cost (34 gross wells)
•
TF 320
2,3
TF
2,3,4
320
Stedman 2-24-H-2
Stedman 3-24-H-3
25 Miles
One 160-acre density test:
$36MM net cost (13 gross wells)
Montana
North Dakota
$123MM net cost (20 gross wells)
TF
2,3
Charlotte 2-22H
Charlotte 3-22H
CLR Core Location
160 160-acre development
Other Lower TF Producer TF CLR Lower TF Producer
320 320-acre development
Current Development: Bakken & Three Forks
BAKKEN (BKKN)
THREE FORKS (TFS)
TECHNICALLY RECOVERABLE
ADDITIONAL INDICATED PAY
OVERPRESSURED BAKKEN PETROLEUM SYSTEM
LODGEPOLE
10,000’
below
surface
Middle Bakken
Upper Bakken shale
Middle Bakken
Lower Bakken shale
660’
660’
1320’
Three Forks 1st Bench
Upper Three Forks
1st Bench
Lower Three Forks
2nd Bench
Lower Three Forks
3rd Bench
Lower Three Forks
4th Bench
NISKU
Three Forks 2nd Bench
Three Forks 3rd Bench
Three Forks 4th Bench
Multiple fracture
stages
Delineation of the Three Forks
Three Forks Thickness Map
Lower Three Forks activity delineates
potential productive footprint of 3,800
Tangrsud
320
square miles in the Bakken
TF
2,3,4
Rosenvold/Farver
Barney
TF
2,3
Stedman
Angus
TF
2,3
TF
2
KOG
Wahpeton
160
TF
TF
2,3
2,3
TF2
TF2
WLL
WLL
WLL
WLL
Rollefstad
320
TF2
TF3
Charlotte
WLL
KOG
TF2
320
North Dakota
Productive Footprint
Montana
18 Lower Three Forks producers
• By operator:
• CLR: 13 wells
• EOG, COP, XTO, ZEN: 5 wells
• Total wells tested:
• TF2: 10 wells
• TF3: 6 wells
• TF4: 2 wells
• Results consistent with expectations
based on core work and areas tested
CLR density projects
WLL
Hawkinson
25 Miles
Industry density projects
21
Industry LTF Producer
Multiple Bench Testing - Charlotte Unit
McKenzie County, ND
E
LDGP
UB
CHARLOTTE
MB Target: 11,294’ TVD
MB
NESSON ANTICLINE
W
Bakken Structure- 200’ Contours
81’
LB
TF1 Target: 11,375’ TVD
TF1
53’
TF2
COLTER
TF2 Target: 11,428’ TVD
37’
TF3 Target: 11,465’ TVD
TF3
20 Miles
123 MBOE produced / 18 months
TF4
68 MBOE produced / 6 months
NSKU
TF2 and TF3 proven productive
Charlotte 2-22H and 3-22H have cumulatively
produced 123,000 Boe and 68,000 Boe
1 MILE
Recently Completed Interference Wells
Existing Wells
No evidence of production interference
between wells in the Charlotte unit
22
Third-Party* Simulation Supports 160-Acre
Spacing
Conclusions of third party
simulation:
8 wells per zone
1st well recovers 1.0
MMBoe
8 wells recover 5.6
MMBoe
8 wells average 700
MBoe per well (70%
of 1-well scenario)
*Ryder Scott Co. LP, Reservoir Solutions, June-August 2012 /Vol. 15 No. 2
•1280-acre unit
•45 ft net pay
•8.4% porosity
• 6900 psi
• 1,000 psi FBHP
• 1,100 BFPD IP
Project Scope
Two parts
• 1 – Drilling and Completions (Eleven new 2 mile horizontal wells)
• 2 – Research and Development
• Core
• Logs
• Vertical Seismic Profiles
• Microseismic
• Pressure data
• 3 D seismic acquisition
Continental Resources
14 wells in 1280 unit
( 4 MB, 3 TF1, 4 TF2, 3 TF3 )
1320’ inter-well spacing
between same-zone wells
5
8
1
3
13
10
4
7
6
2
11
9
200 ‘ +/-
Hawkinson (Sec. 22 & 27-147N-96W)
1,280 Acre Unit Full Development Project
14
12
?
1320’
660’
Monitor well as of 11/20/12
68’
1
MILE
Established producing wells
10 frac’d wells microseismic program
Wells frac’d from W, C & E Pads
Goals
Define reservoir drainage of the MBK, TF1, TF2 & TF3
Confirm whether these formations are distinct and
separate from each other
Determine appropriate well spacing required for most
efficient reservoir drainage
Increase spacing unit ultimate recovery
Predict areas of future reservoir sweetspots
Optimization of Wellsite Operations
Areas to Be Addressed
• Project specifics will be steered by program partners.
• Focus areas:
– Flare gas collection and utilization
– Improved waste handling and options for beneficial
reuse
– Options for water recycling, treatment, and reuse
– Other surface and downhole operational issues
(corrosion, scaling, casing integrity)
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Success Stories
• The EERC has learned that successful projects entail
involvement and partnership with industry and other key
stakeholders (i.e., North Dakota Petroleum Council, Oil
and Gas Research Council, North Dakota Division of
Mineral Resources).
• The Bakken Optimization Program is following the same
model.
• Project example related to flaring:
– Evaluation of Associated Gas Use
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Qualitative Summary of Evaluated
Technologies
Gas Use Range,
Mcfd
NGL Removal
Requirement
Scalability to
Resource
Ease of
Mobility
Likelihood of
Deployment at
Small Scale
1000–1800
Minimal
Very scalable
Very easy
Very likely
300–600
Minimal
Very scalable
Very easy
Very likely
50+
Yes
Scalable
Very easy
Possible
Chemicals
1,000,000*
No
Not scalable
Not mobile
Very unlikely
Fertilizer
300–2000
No
Scalable
Not easy
Possible
Technology
Power – Grid Support
Power – Local Load
Compressed Natural Gas
(CNG)
* Typical commercial-scale plant.
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Summary of Evaluated Technologies
Technology
Capital Cost
NGL Recovery
$2,500,000
$700,800
Power – Grid Support
$7,500,000
$1,665,000
+$1,170,000
NGL value
Reciprocating engine, 5-MW
Power – Local Load
$3,200,000
$158,000
+$700,800
NGL value
Reciprocating engine, 1-MW
CNG
$3,900,000
$306,000
+$700,800
NGL value
1-million-mile fleet
$17,000,000–
$52,000,000
$3,700,000–
$23,000,000
Fertilizer
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Annual Revenue
Basis
600 Mcf/day
20–90 ton/day production
Updated Flare Gas Data – May 2013
Flaring Allocation by Total
Gas Flared
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Flaring Allocation by Number
of Wells
New Flare Data Analysis – May 2013
Flared Gas
Gathered and Unconnected Wells
Wells without gas sales
2,743,746 Total Mcf
41%
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3,940,481 Total Mcf
59%
Wells with gas sales
Evaluation of Associated Gas Use
• Bifuel Rig Demonstration – assessment of fuel savings
and operational impacts of associated gas–diesel mix
• Associated Gas Alternative
Use Study – analysis of gas
use options upstream of gasprocessing plants
– Small-scale gas processing
– CNG/liquefied natural gas
(LNG) for vehicles
Image: http://infinitosrl.net/
– Electric power production
– Chemical production
EERC Study and Final Project Report
www.undeerc.org/Bakken/researchstudies.aspx
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A Use for Flared Natural Gas
• Power production for drilling rigs
is a near-term opportunity.
• Diesel engines properly outfitted
with bifuel systems can utilize a
mixture of diesel and natural gas.
• Significant fuel savings can be
achieved:
– 30%–60% reduced fuel costs
– Reduced fuel delivery and
associated traffic, engine
emissions, and fugitive dust
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Image: www.drillingcontractor.org
Summary of Results
• Diesel fuel consumption reduced by 18,000 gallons for
two wells over a period of 47 days.
• Fuel-related net cost savings of nearly $60,000.
• Reduced delivery truck traffic.
• Reduced NOx emissions and increased CO and HC
emissions compared to diesel-only operation. Mitigation
achievable with exhaust gas treatment.
• Seamless engine operation using the GTI Bi-Fuel®
system.
• Currently ECO-AFS has Bi-Fuel® on 21 rigs and 200
generators in North Dakota.
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Impact of Widespread Use
• Nearly 200 drilling rigs in operation at any given time
• 1,800,000 Mcf of wellhead gas used per year
• 18,000,000 gallons of diesel fuel saved per year
• $72,000,000 diesel fuel cost saved per year
• 3600 fuel deliveries avoided per year
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Path Forward
• Continental’s efforts are well under way.
• Initial scopes of work have been formulated to address
some of industry’s operational issues and are being
reviewed by program partners:
– Characterization of Bakken/Three Forks waste streams
– Bakken well failure analysis and mitigation
– Flaring mitigation via gathering system optimization
– Evaluation of water-recycling and reuse options,
applicability, and costs
• This program is just starting, so NOW is a good time to
become a member!
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Thanks to Our Partners
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For More Information…
Check out the EERC’s booth in the exhibit
area!
John Harju, Associate Director for Research
Energy & Environmental Research Center
(701) 777-5157; jharju@undeerc.org
Stan Wilson, Manager, Resource Development
Continental Resources, Inc.
(405) 234-9163; Stan.wilson@clr.com
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