How Synergy saved time and increased proppant placement

Overview 

Synergy Resources produces oil and gas from more than 375 wells in the Denver-Julesburg (DJ) basin. They have drilled more than 145 of those since 2009. The operator constantly looks for ways to drill and complete wells more effectively and efficiently. When they experienced problems completing wells on one pad in 2014, Halliburton approached them about using new pump-down technologies that could help avoid similar problems in a zipper frac on the next pad. Comparing the two experiences provides a unique opportunity to assess the value of three new technologies: Pump-Down Visualization (PDV) service, the Mono-Conductor Tension Device (MCTD), and MaxForce®-FRAC charges. Together, they sped up pump-down operations, saved money, reduced NPT, reduced water consumption, and helped place more proppant compared to traditional technologies.

Challenge  

In early 2014, Synergy experienced problems completing wells on one of its many pads. Halliburton approached them about using new pump-down technologies in a zipper frac on their next pad to help avoid similar problems. Comparative completion analysis and controlled experiments provided insight into the value of Halliburton’s three unique and proprietary technologies. Together, they sped up pump-down operations, saved money, saved water, reduced NPT, and helped place more proppant compared to the traditional technologies used on the previous pad.

Solution

In the DJ basin, Halliburton wireline field professionals typically pull out of the hole at 200-250 ft/min. Several factors limit this speed: wellbore conditions, client preferences, professionals’ comfort level, and most importantly, the force applied at the cable head weak point (the point designed to fail at a known overpull in the event that the gun string gets stuck). But until the MCTD, field professionals had no way to measure tension at the weak point; they could only measure it at the wellhead. Out of caution, Halliburton pulled out of the first well at 200-220 ft/min. By using the MCTD on the second pad, field professionals could see tension on the weak point in real time, allowing them to pull out at 400-600 ft/min – almost a 3X increase. This reduced stage time. On the second pad, wireline waited on frac from 45 to 90 minutes after coming out of the hole on each stage. This is far better than frac waiting on wireline due to associated standby costs.

A stage-to-stage test of MaxForce®-FRAC charges and a leading alternative charge within two wells compared breakdown pressures, treating pressures, and volume of proppant placed. Results showed up to 10-percent reductions in breakdown pressures and up to 3-percent reductions in treating pressure on the MaxForce®-FRAC stages.

Result

Together, these new technologies helped Synergy avoid the cost of a second coiled tubing run plus associated standby charges for a frac crew. Faster running speeds also meant that expensive frac crews never had to wait on less expensive pump-down crews. Finally, they reduced the amount of scarce water used, brought the well into production sooner and increased the volume of proppant placed, an important consideration for future well productivity.