Completion Strategies, Bakken 4.0, Whiting, WPX -- March 29, 2020

Completion strategies, Bakken 4.0, Whiting. For more, see completion strategies, Bakken 4.0, linked at the sidebar at the right.

Case studies, two WPX wells coming off confidential list this next week:

• 36502, drl, WPX, Skunk Creek 1-12HW,  33-025-03824, South Fork, t--; cum 8K over 23 days; fracked 1/9/20 - 1/17/20; 4.9 million gallons of water; 83.3% water by mass; friction reducer, 0.02466, extremely low on a percentage basis;

• 36503, drl, WPX, Skunk Creek 1-12HA, 33-025-03825, South Fork,  t--; cum 10K over 22 days; fracked 1/8/20 - 1/17/20; 4.9 million gallons of water; 83.4% water by mass; friction reducer: 0.02537, extremely low on a percentage basis;

Example of portion of FracFocus report:

Frack data that catches my attention:

• total gallons of water, less than 6 million gallons or more than 12 million gallons
• percentage of water by mass: less than 88% or more than 92% 
• friction reduction by percent: less than 0.04000 or more than 0.05000 (a reader brought this to my attention, thank you very much)

Whiting 3Q18 Corporate Presentation -- December, 2018

Before we get to the Whiting presentation.  From the EOG 3Q18 corporation presentation, this is how much it cost EOG to drill/complete a Bakken well in 2018:

• $4.6 million

This is how much it cost EOG to drill/complete a well in the Bakken in 2012:

• $10 million

Now, back to the Whiting 3Q18 presentation.

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Updates

March 23, 2019: in the presentation below, there is no mention of "Generation 5.0" fracking by Whiting. In early 2019, Whiting began talking about Generation 5 fracking. With Generation 5.0 fracking, Whiting feels that a lot of their Tier 2 areas will become Tier 1. In addition, Whiting is talking about adding more acreage.

Original Post

Link here.

December 6, 2018.

Only a few items that might be different from earlier presentations.

33 slides total.

• Strategic vision: 
• reduce debt and deliver free cash flow at $55 NYMEX oil price
• maintain a strong hedge position (60 - 70% of oil volumes), 12 - 14 months forward
• Results:
• 3Q18: net cash exceeded CAPEX by $56 million 
• 3Q18: discretionary cash flow exceeded capital expenditures by $90 million
• forecast: 129,000 boe/d
• Williston Basin operated production forecast to grow 13% 4Q year-over-year (2018 over 2017)
• plan to drill 120 Bakken/Three Forks in the Williston Basin in CY2018
• plan to put on production (POP) 123 wells in Williston Basin in CY2018
• cash flow, historical, in millions
• 4Q17:  $96
• 1Q18: $103
• 2Q18: $56
• 3Q18: $90
• four-quarter total: $355
• Among 12 peers: #1 in generating peer leading cash flow
• only two peers: positive cash flow
• ten peers: with negative cash flow
• Williston Basin acreage
• Whiting is now #1 in acreage across the core Williston Basin
• Tier 1 areas: 296,063 net acres
• East Missouri Breaks
• Foreman Butte
• Hidden Bench
• Polar
• Sanish/Polar
• Tier 2 areas: 171,038 net acres
• Pronghorn
• West Missouri Breaks
• Other (probably Wildrose area)
• Total net acres: 467,101 net acres in Williston Basin
• 2018 deal
• Bakken bolt-on
• 54,833 net acres
• $130 million
• new acres overlap Hidden Bench, East Missouri Breaks acreage
• 1,290 boepd
• $2,370 / acre
• McNamara Infill Project: Sanish
• four sections (22/23/26/27)
• drill/complete six Bakken infill wells
• parent wells: 9 parent wells completed in 2007 and 2012
• seven middle Bakken wells; two Three Forks wells
• sounds like 15 wells across four sections
• project has produced more than 1.5 million bbls oil
• projected DSU recovery factor prior to McNamara infill wells: 11%
• projected DSU recovery factor including McNamara infill: 20%
• Sanish generation 4.0 Bakken completions; graph highlights three DSUs
• McNamara (220 days production)
• Sanish Bay (190 days production)
• Bartelson (60 days production)
• Western Sanish generation 4.0 Bakken wells outperform  by 83%
• Bartelson parent: 35K bo at 60 days
• Bartelson children: 65K bo at 60 days
• Pinwheel pad -- I think CLR had one of the first of these designs
• 8 new Bakken wells
• 6 new Three Forks wells
• 2 existing wells
• spud to TD average: 9.3 days
• 76 daysof fracking, 100 million lbs proppant, 2 million bbls fresh water
• will come in 8% under budget
• Generation 4.0 Bakken completions (2018)
• 600 - 1,200 lbs/ft proppant
• 200' - 300' stage spacing
• 15 - 40 bbl/ft fluid
• 30' to 50' cluster spacing
• Generation 3.0 (2016 - 2017)
• Generation 2.0 (2013 - 2015)
• Generation 1.0 (2010 - 2012)

Much, much more at the link.

Disclaimer: this is not an investment site. Do not make any investment, financial, job, travel, or relationship decisions based on what you read here or what you think you may have read here.

Fracking:

• 10,000-ft lateral
• about 8 million lbs proppant
• about 40 stages

Whiting Operations Update

This was previously reported but reached me today via the Oil and Gas Journal.

October 28, 2010: The estimates of the recoverable oil reserves in the North Dakota Middle Bakken (MB) and Three Forks (TFS) formations continue to pleasantly surprise Whiting Petroleum Corp., Denver, which said that it also appears that further infill drilling is warranted in Sanish field. 

Sanish oil field, "owned" by Whiting

• Whiting operates 152 wells in the Sanish
• Additional frac stages have contributed to higher initial production rates
• Currently: 27,385 boepd from MB and TFS
• 3Q10: 22,275 boepd from the Sanish, up 113% from 3Q09

Sanish field operations

• Whiting says it now expects to drill 534 gross operated wells in the Sanish (an additional 152 operated wells)
• 83 will be "wing wells," medium length laterals (7,500 feet); will be drilled in the northeast and southwest portions of the 1,280-acre spacing units
• Will now drill three TFS wells per 1,280-acre units rather than previous plan of two TFS wells per unit
• Will add 80 gross well locations in the Sanish
• Estimates that 323 gross wells remain to be drilled

Production

• 57 wells through mid-October for calendar year 2010
• 51 Bakken wells: average boepd = 2,541 (21% more than average before 2010)
• 7 TFS wells: average boepd = 1,433  (42% more than average before 2010)

Fracture stimulation

• 15 - 30 fracs/well in 2010; average = 20/well
• Before 2010, most wells were fracked with 10 stages
• Using more proppant and fluid now: 50K bbl fluids and 4 million lbs

Rigs and Fracking Crews, Cost and Time, Transportation

Whiting plans to maintain nine operated rigs in the Sanish through 2012 
Whiting has one dedicated frac crew at Sanish; 100 wells/year
Cost: <$5 million/well
Average 20,000 feet measured depth; 10,000 ft lateral
Average length of time: 19 days
19 fewer days on location saves $900,000 in drilling costs
Whiting expects to have all Sanish oil connected to pipeline by end of 2010

Parshall field

• Some participation in 129 wells
• Lewis and Clark Prospect: Stark County
• Golden Valley, Billings and Stark counties
• Froehlich well: averaged 1,109 boepd in first 30 days
• Discovery well: Federal 32-4TFH: flowed 1,970 boepd from the TFS, Nov 2009
• One year later, Federal 32-4TFH continues at 259 boepd (pumping), 32 boepd higher than the well's production rate at the end of July, 2010
• Four operated rigs; will increase to five by end of November; plans to have nine by mid-2011. 
• Goal: 13 TFS wells in 2011
• Plan: 30 frac stages
• Estimates at least 500 potential wells targeting the TFS