williston basin petroleum conference advances in technology panel efficient fracture stimulation...
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Williston Basin Petroleum Conference Williston Basin Petroleum Conference
Advances in Technology Panel
Efficient Fracture StimulationEfficient Fracture Stimulation
Rick Ross – Whiting Petroleum Corporation
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Forward-Looking Statement Forward-Looking Statement DisclosureDisclosure
This presentation includes forward-looking statements that the Company believes to be forward-looking 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 forward-looking 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.
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OutlineOutline
• 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
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Completion Objectives 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
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Horizontal Wellbore ConfigurationHorizontal Wellbore ConfigurationHorizontal Wellbore ConfigurationHorizontal Wellbore Configuration
Packer Assembly Run to ~ 10,000Packer Assembly Run to ~ 10,000’’ Lateral Distance Lateral DistancePacker Assembly Run to ~ 10,000Packer Assembly Run to ~ 10,000’’ Lateral Distance Lateral Distance
77”” Casing Casing77”” Casing Casing4 ½4 ½”” Liner with Liner with Swelling Packers &Swelling Packers &Sliding SleevesSliding Sleeves
4 ½4 ½”” Liner with Liner with Swelling Packers &Swelling Packers &Sliding SleevesSliding Sleeves
~10,000~10,000’’ VerticalVertical
Courtesy of Baker Hughes Inc.Courtesy of Baker Hughes Inc.
300-400300-400’’ 300-400300-400’’
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Evolution of Sleeve SystemsEvolution 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
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Evolution of Sleeve SystemsEvolution of Sleeve Systems
•Future?
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Current Completion StrategyCurrent 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
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Benefits of Sliding SleevesBenefits 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.
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Considerations for Full Field DevelopmentConsiderations 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
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Fully Developed Bakken and Three Forks Fully Developed Bakken and Three Forks Horizontal Wells in Sanish Field AreaHorizontal Wells in Sanish Field Area
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Best Practices: Best Practices: Post Frac – Flow Back TechniquesPost 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.
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Kinnoin 21-14
0
500
1000
1500
2000
2500
3/9/2010 0:00 3/9/2010 12:00 3/10/2010 0:00 3/10/2010 12:00 3/11/2010 0:00 3/11/2010 12:00 3/12/2010 0:00
Date & Time
Su
rfac
e P
ress
ure
IP Test
balls off seat
Best Practices: Best Practices: Post Frac – Flow Back TechniquesPost Frac – Flow Back Techniques
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Best Practices: Best Practices: Post Frac – Flow back TechniquesPost Frac – Flow back Techniques
• Question – Are the frac balls recovered during flow back?
• Answer - A recent 30 stage completion flowed back 30 of 30
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Controlling Well CostsControlling Well Costs
Upward Pressure•Dedicated service contracts
•Diesel costs (fuel surcharges)
•Sand price increases
•Potential Guar shortage
•Overall upward movement in services and equipment
Downward Pressure•Reduction in drilling time
•Pad drilling/ common facilities
•Efficient completions with sleeve systems
•Reduction in cycle time
•Dedicated frac crews - scheduling
•Increased services
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0 40 80 120 160 2000
1000
2000
3000
4000
5000
OilCum6Months ( Mbbl )
IP B
OE
PD
( b
bl/d
)
WHITING OIL AND GAS CORPORATION
Date:2/15/2012
Bakken Wells in North DakotaBakken Wells in North DakotaCompleted after 1/1/2008 with 6 Months Production – 1817 Wells
Source: NDIC website
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BackupBackup
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General Bakken Formation DataGeneral 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
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Bakken Regional SettingBakken Regional SettingBakken Regional SettingBakken Regional Setting
Modified after Meissner, 1983 & Peterson and MacCary, 1987
0 40 80 120 1600
800
1600
2400
3200
4000
OilCum6Months ( Mbbl )
IP B
OE
PD
( b
bl/d
)
WHITING OIL AND GAS CORPORATION
Date:3/15/2012
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Three Forks Wells in North DakotaThree Forks Wells in North DakotaCompleted after 1/1/2008 with 6 Months Production – 497 Wells
Source: NDIC website