Optimized Production in the Bakken Shale: South Antelope Case Study
- David R.M. West (SigmaCubed) | John Harkrider (SigmaCubed) | Monte R Besler (FRACN8R Consulting) | Michael Barham (Helis Oil & Gas) | Kenneth Mahrer
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- September 2014
- Document Type
- Journal Paper
- 344 - 352
- 2014.Society of Petroleum Engineers
- hydraulic fracturing
- 1 in the last 30 days
- 541 since 2007
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Focused modifications in drilling, reservoir, and completion engineering from 2009 to the present have improved Bakken, specifically the South Antelope field, production as much as 50 to 75%. To achieve these results, Helis Oil and Gas Company formed a multidisciplinary team in 2008 that was tasked with evaluating and overhauling its completion approach. Pre-2008 completions followed conventional wisdom: Target the Middle Bakken formation between the Lodge Pole and the Three Forks formations. Pre- 2009 wellbore constructions included “kick outs” (i.e., multilaterals); openhole completions; short laterals; single-stage ported subs; sliding sleeves; and long stage intervals; and they were erratic and inconsistent. The designs and procedures resulted in a high percentage of premature screenouts. In addition, the production responses on these Middle Bakken completions averaged 330 BOPD with an estimated ultimate recovery (EUR) of 300,000 bbl of oil equivalent. During the pre-2009 period, three Three Forks were completed, and these wells produced, on average, 550 BOPD. After evaluating the pre-2009 results, the team recommended ten Changes: (1) change landing target to the Three Forks; (2) increase lateral lengths approximately two-fold from short laterals (“640s”) to long laterals (“1280s”); (3) increase formation contact (completion method, stage lateral length, and perforation spacing/density); (4) refine pumpdown operations; (5) implement critical-fracturing mechanism diagnosis; (6) incorporate proppant selection (ceramic vs. sand); (7) refine flush procedure to include monitoring and ensure consistency; (8) integrate on-site, real-time pressure management and proppant schedule including proppant slugs, altered mesh types, and adjusted ramp schedule; (9) adjust treatment-fluid design (25-lbm gel loading instead of 40-lbm gel loading); and (10) implement flowback and flow-rate control. Implementing these recommendations, Helis deviated from conventional Williston Basin philosophy and drilled 30 “1280s” during 2010–2012. These wells resulted in approximately 1,500 BOPD with a maximum of 2,500 BOPD and EURs of approximately 1.2 million BOE. They are among the best wells in the Williston basin. In comparison, direct offset-well EURs averaged less than 750,000 BOE. The success of these wells is not the result of one breakthrough but rather the result of sound changes to engineering techniques that were carried out systematically. Applying these engineering practices, maintaining strict adherence to recommended practices, and not making dramatic, unfounded changes ultimately optimized production in this Bakken project.
|File Size||1 MB||Number of Pages||9|
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