Optimized Production in the Bakken Shale: South Antelope Case Study

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 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-fracturingmechanism 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, directoffset-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.

Predicting Frac Stage Differential Stress and Microseismicity Using Geomechanical Modeling and Time Lapse Multi-Component Seismic - Application to the Montney Shale

“…On the other hand if we focus only on the variations in well performance caused by completions technologies, we notice that the best combination of completions strategies will yield an improvement in well performance that ranges from 30% to 100% in the best cases. For example, West et al (2014) reached up to 75% improvement in the Bakken performance by applying a wide range of engineering techniques while Schlosser et al (2015) had about 60% improvement in cumulative oil in the Shaunavon tight oil play when shifting from open hole with low proppant tonnage to cemented liner with high proppant tonnage. In other words, completion optimization is a two-pronged optimization strategy: the first optimization strategy must focus on the Geologic Heritage and the Stressful Environment which is the first order controlling factor on well performance, followed by a second optimization strategy focused on completion techniques which represents a second order factor in well performance.…”

Artificial Intelligence Applications in Reservoir Engineering: A Status Check

“…He also pointed out the importance of AI system by analyzing the real-time pressure and production data for the purpose of monitoring the well performance and diagnosing the inter-well connectivity [76]. In the unconventional reservoir development area, literature surveys indicate that the importance of analyzing the real-time pressure data during the hydraulic fracture treatment cannot be overemphasized since such data would provide significant information regarding the petrophysical and geomechanical characteristics of the near-wellbore regions [77,78]. We can foresee potentials of establishing intelligent systems to quickly analyze the real-time pressure measurement during the fracking treatment job and provide a better understanding of the near-wellbore environment [79].…”