Williston Basin Petroleum Conference
Efficient Fracture Stimulation
Advances in Technology Panel
Rick Ross – Whiting Petroleum Corporation
1
Forward-Looking Statement
Disclosure
This presentation includes forward-looking statements that the Company believes to be forwardlooking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All
statements other than statements of historical fact included in this presentation are forwardlooking statements. These forward looking statements are subject to risks, uncertainties,
assumptions and other factors, many of which are beyond the control of the Company. Important
factors that could cause actual results to differ materially from those expressed or implied by the
forward-looking statements include the Company’s business strategy, financial strategy, oil and
natural gas prices, production, reserves and resources, impacts from the global recession and
tight credit markets, the impacts of hedging on our results of operations, level of success in
exploitation, exploration, development and production activities, uncertainty regarding the
Company’s future operating results and plans, objectives, expectations and intentions and other
factors described in the Company’s most recent Annual Report on Form 10K. In addition,
Whiting’s production forecasts and expectations for future periods are dependent upon many
assumptions, including estimates of production decline rates from existing wells and the
undertaking and outcome of future drilling activity, which may be affected by significant commodity
price declines or drilling cost increases.
2
Outline
• Completion objectives and methods utilized
• Evolution of completion tools, current state and
future
• Strategies for full field development
• Flow back practices
• Cost control
• Whiting performance
• Summary
3
Completion Objectives
• Maximize Stimulated Reservoir Volume
– Good distribution of stimulation across
the lateral
• Optimize cost, performance, and logistics
of stimulation strategies utilized
– Fluids
– Diversion
– Proppant
– Pressure pumping service availability
4
Horizontal Wellbore Configuration
~10,000’
Vertical
Courtesy of Baker Hughes Inc.
4 ½” Liner with
Swelling Packers &
Sliding Sleeves
7” Casing
300-400’
Packer Assembly Run to ~ 10,000’ Lateral Distance
5
Evolution of Sleeve Systems
• First sleeve system was utilized in Sanish field in December
2007 – (8 stages)
• Expanded number of stages up to 24 – Nov 2009
• Hybrid systems to achieved 30 stages– but inefficient & costly
• First 30 stage sleeve system (1/16” increments) Feb 2011
• Development of 40 stage system. – March 2011
– “Standard” long lateral is 30 stages
• Multi port systems – field tested in several Sanish wells
6
Evolution of Sleeve Systems
• Future?
7
Current Completion Strategy
• Utilize oil swelling packers and sliding sleeve system (ball
actuated).
– Number of stages utilized based on rock properties and area
performance.
– Use a 30 stage sleeve system with “long lateral”.
Approximate Job Volumes for a 30 Stage System:
1.8 - 3.0 MM# total proppant
• Small mesh sand for fluid loss
• 20/40 mesh natural sand for main stages
25,000 – 30,000 bbls water
8
Benefits of Sliding Sleeves
• Optimize utilization of frac crew – 30 stage job frac
is less than 24 hrs.
• Lower completion cost.
– Lower frac ticket cost due to efficiency of operations
– No “drill out” required
• Advantage in winter operations.
• Less load water – gun pump downs, flush volume.
9
Considerations for Full Field Development
• Early development generally focused on holding acreage
and delineation of acreage.
• Especially where both Bakken and Three Forks are
prospective, potential for communication exists.
• Areal conformance important
10
Fully Developed Bakken and Three Forks
Horizontal Wells in Sanish Field Area
11
Best Practices:
Post Frac – Flow Back Techniques
• Complete construction of battery and if possible gas connection prior
to stimulation.
• Lateral Section clean-up during flow back
– Pressure differential allows balls in the toe section to come off seat.
– Flow back on a 48/64th choke for 6-8 hours, and then run “IP test” after
the well reaches 50% oil cut.
– Have run tracers in frac stages to understand individual zone
contribution during flow back.
– Clean out of lateral is usually not warranted – but exceptions.
12
Best Practices:
Post Frac – Flow Back Techniques
Kinnoin 21-14
2500
Surface Pressure
2000
1500
IP Test
1000
500
balls off seat
0
3/9/2010 0:00
3/9/2010 12:00
3/10/2010 0:00
3/10/2010 12:00
Date & Time
3/11/2010 0:00
3/11/2010 12:00
3/12/2010 0:00
13
Best Practices:
Post Frac – Flow back Techniques
• Question – Are the frac balls recovered during flow back?
• Answer - A recent 30 stage completion flowed back 30 of 30
14
Controlling Well Costs
Upward Pressure
Downward Pressure
•
•
•
•
•
•
•
•
Dedicated service contracts
Diesel costs (fuel surcharges)
Sand price increases
Potential Guar shortage
Overall upward movement in
services and equipment
•
•
•
Reduction in drilling time
Pad drilling/ common facilities
Efficient completions with sleeve
systems
Reduction in cycle time
Dedicated frac crews - scheduling
Increased services
15
Date:2/15/2012
Bakken Wells in North Dakota
Completed after 1/1/2008 with 6 Months Production – 1817 Wells
Source: NDIC website
5000
WHITING OIL AND GAS CORPORATION
IP BOEPD ( bbl/d )
4000
3000
2000
1000
0
0
40
80
120
OilCum6Months ( Mbbl )
160
200
16
17
Questions?
Contact Information:
Rick Ross
(303) 837-4236
rickr@whiting.com
18
Backup
19
General Bakken Formation Data
• Reservoir and Fluid Properties
– Depth: ~10,000’
– Bottom Hole Temperature: 210 F
– Reservoir Pressure: 5,000 – 7,000 psig
– Pressure Gradient: 0.5 – 0.7 psi/ft
– Bubble Point: 1,800 – 3,000 psig
– Solution GOR: 500-1,500 scf/bbl
– Permeability: 0.0001 – 1 md
– Frac Gradient: 0.76 – 0.85 psi/ft
Middle Bakken Core - Sanish Field
20
Bakken Regional Setting
Modified after Meissner, 1983 & Peterson and MacCary, 1987
Date:3/15/2012
Three Forks Wells in North Dakota
Completed after 1/1/2008 with 6 Months Production – 497 Wells
Source: NDIC website
4000
WHITING OIL AND GAS CORPORATION
IP BOEPD ( bbl/d )
3200
2400
1600
800
0
0
40
80
OilCum6Months ( Mbbl )
120
160
23