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Optimized Production in the Bakken Shale: South Antelope Case Study

David R. M. West, SPE, and John Harkrider, SPE, SIGMA3; Monte R. Besler, SPE, FRACN8R Consulting, LLC; Michael Barham, SPE, Helis Oil & Gas Company, LLC; Kenneth D. Mahrer, Ph. D., SPE, SIGMA3

Abstract

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 Co., LLC formed a multi-disciplinary team in 2008 which it 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., multi-lateral), open-hole completions; short laterals; single-stage ported subs; sliding sleeves; and long stage intervals and were erratic and inconsistent. The designs and procedures resulted in a high percentage of pre-mature screenouts. In addition, the production responses on these Middle Bakken completions averaged 330 bopd with an estimated ultimate recovery (EUR) of 300 MBOe. During the pre-2009 period, 3 Three Forks were completed and these wells produced on average 550 bopd. After evaluating the pre-2009 results, the team recommended 10 changes: (1) change landing target to the Three Forks; (2) increase lateral lengths ~2x from “640’s” to “1280’s”); (3) increase formation contact (completion method, stage lateral length and, perforation spacing/density); (4) refine pump-down operations; (5) implement critical fracturing mechanisms diagnosis; (6) incorporate proppant selection (ceramic versus sand); (7) refine flush procedure to include monitoring and assure 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-lb gel loading instead of 40-lb gel loading); and (10) implement flowback and flowrate control. Implementing these recommendations, Helis deviated from conventional Williston Basin philosophy and drilled 30 “1280’s” in 2010-2012. These wells resulted in ~1,500 bopd with a maximum of 2,500 bopd and EUR’s of ~1,200 MBOe. They are among the best wells in the Williston Basin. In comparison, direct offset well EUR’s averaged less than 750 MBOe. 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 drastic, unfounded changes ultimately optimized production in this Bakken project.


Copyright 2013, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Unconventional Resources Conference-Canada held in Calgary, Alberta, Canada, 5–7 November 2013.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

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