Playbooks Supplements

Unconventional Yearbook 2018

Issue link:

Contents of this Issue


Page 81 of 107

80 | January 2018 | 2018 UNCONVENTIONAL YEARBOOK | COMPLETION OPTIMIZATION "Oil in place and recovery factors are also import- ant. All unconventional plays are not created equal. You have to understand the reservoir to get the spacing and lateral length right. Unconventional plays are benefi tting from all the continuous learn- ing that's taking place. We want to learn as much as we can as quick as we can to eliminate over-spacing the wells and depletion and pressure drop issues within the reservoir." In addition to reservoir pressure, Downey added that the length of a lateral typically comes down to the operator's ability to effectively stimulate the stage toward the toe of the well. He also said that lowering the cluster spacing maximizes the reser- voir coverage along the lateral, while increasing the number of clusters per stage reduces the number of stages to be pumped. According to its second-quarter 2017 earnings presentation, Energen Resources is deploying its Generation 3 well completion operation in the Delaware and Midland basins. The company's fi rst iteration, Generation 1—implemented in the Dela- ware between 2012 and 2014—featured 1,000 lb/ft of proppant, 240-ft stage spacing, 39 bbls/ft of fl uid and 50-ft cluster spacing. In the Midland Basin, Generation 1 completions featured 1,250 lb/ft to 1,400 lb/ft of proppant, 250-ft to 300-ft stage spac- ing and 65-ft to 75-ft cluster spacing. By 2016 and into 2017, Energen had deployed its Generation 3 wells in the Midland and the Del- aware basins. In the Delaware, those completions featured up to 2,400 lb/ft of proppant, 200-ft stage spacings, 40 bbls/ft of fl uid and 33-ft cluster spac- ings. In the Midland, completions featured up to 2,000 lb/ft of proppant, 150-ft stage spacing, up to 45 bbls/ft of fl uid and 30-ft cluster spacing. According to its third-quarter 2017 earnings report, Continental Resources recently completed its third 10-well pattern density project in the Scoop Woodford condensate window, which set an Okla- homa record for an initial rate from a drilling spac- ing unit. The company's Sympson unit produced at a combined peak 24-hr rate of 41,701 boe/d. Accord- ing to Continental, the Sympson unit is a 2-mile- long, dual zone, 10-well pattern that includes 14 wells. The 1,280-acre unit required a pair of 1-mile parent wells and 12 child wells to fi ll the 10-well pat- tern. The 12 new wells, which averaged lengths from 3,050 ft to 10,270 ft, produced at an average 24-hour peak production rate of 3,145 boe/d. Operators in basins across all of North America are discovering these longer laterals are producing often record rates of IP. But Isaac Aviles, Schlumberger tech- nical principal for multistage stimulation, said that increased lateral lengths and stage count should be weighed against their fi nancial benefi ts. "Depending on the basin, the additional oper- ational process (and the increased cost) may not yield economic results," he said. In a recent Schlumberger study in the Barnett, the relationship between lateral length and well performance was explored. From a production per- spective using data analytics, no distinctive advan- tage was found for wells drilled with longer laterals. Furthermore, using engineering simulation for the basin, it was found that under certain conditions the linear relationship between production versus lateral length can be negatively affected when going beyond 10,000 ft to 12,000 ft. These fi ndings com- plement a separate Schlumberger study of stage counts in the Bakken, aimed to determine if the economic limit—or stage count per lateral foot— had been reached. In some sections of the play, this was found to be the case. "In these studies, lateral length and/or stage count were examined to gauge the production impact of spacing or extended reach," Aviles said. "It was found that in certain circumstances the associated cost of completions was not be fi nan- cially compensated by the production gains. Anal- yses as such as the ones above need to be done on a regular basis to determine how the production and economic performance may change across the basin and over time." Maintaining 'parent' well production As operators drill and complete more wells on their wellpads with tighter spacing in North America's shale fi elds, older, more mature wells have come under risk of declining production. The issue of "frack hits" is on the rise as well spacing with infi ll wells becomes tighter, according to Highlands Natural Resources. Highlands has developed a technology, DT Ultravert, which is designed to protect against well

Articles in this issue

Links on this page

Archives of this issue

view archives of Playbooks Supplements - Unconventional Yearbook 2018