Synergy Resources produces oil and gas from more than 375 wells in the Denver-Julesburg (DJ) Basin, and more than 145 of those have been drilled since 2009. An operator constantly looks for ways to drill and complete wells more effectively and efficiently, as was the case for Synergy. After experiencing problems completing wells on one pad in 2014, Halliburton approached Synergy about using new pump-down technologies that could help avoid similar problems in a zipper frack on the next pad. Comparative completion analysis and controlled experiments provided insight into the value of Halliburton’s three unique and proprietary technologies: Pump-Down Visualization (PDV) service, the Mono-Conductor Tension Device (MCTD) and MaxForce-FRAC charges. Together these tools sped up pump-down operations, saved money and water, reduced nonproductive time and helped place more proppant compared to traditional technologies used on the previous pad.

Reduced time per stage

In the DJ Basin, Halliburton wireline field professionals typically pull out of the hole at a conservative speed to reduce the risk of unplanned events downhole, such as an unintentional separation of the tool from the wireline cable. Several factors limit this speed, including wellbore conditions; client preferences; professionals’ comfort level; and, most importantly, the force applied at the cable head weak point, which is designed to fail at a known overpull should the gun string get stuck. Until the introduction of 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 61 m/min to 67 m/min (200 ft/min to 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 122 m/min to 183 m/min (400 ft/min to 600 ft/min), an increase of almost three times. This reduced stage time. On the second pad, wireline waited on frack from 45 to 90 minutes after coming out of the hole on each stage. This is far more efficient than frack waiting on wireline because of lower associated standby costs.

Avoiding an extra CT job

Operators sometimes use coiled tubing (CT) to perforate the toe of a well if pumping down guns is not an option. After the first stage, however, pump-down operations on wireline are considerably faster barring unforeseen circumstances such as getting stuck, presetting a plug or not being able to reach the perforating depth. In such cases, a CT unit must be called a second time, resulting in extra CT costs and standby charges for a frack crew. A single CT run in the DJ Basin can cost up to $50,000.

When trying to perforate the second stage of wells on the second pad with wireline, the crew encountered problems reaching shooting depth. Wellhead pressures approached kick-out pressures of pump trucks (8,500 psi). The latter had to be increased so pump-down could continue. On three separate occasions in the horizontal, surface tension and casing-collar locator responses indicated a stall. The MCTD, however, showed an average of 35 lb of tension on the string, with spikes near 100 lb, indicating slow tool movement.

In each case, when the tool supposedly “stalled,” the MCTD and PDV software indicated the string was still in motion.

Reducing pump-down water needs

Another MCTD benefit is that it helps professionals reduce the amount of water used to pump tools down. Water is precious in the semi-arid DJ Basin. Yet because pump-down crews lack real-time feedback, they generally use more water than needed to pump guns downhole. It may take several stages or wells to gain the experience that shows the optimum pump rate for tool deployment.

Excessive water can cause erratic tool movement, while too little reduces running speed. With the MCTD, the crew can optimize flow and speed based on real-time downhole tension observations. There is no learning curve in finding the sweet spot.

Halliburton compared water consumption on several other wells in the vicinity owned by Synergy and other operators. They all had similar 4.5-in., 13.5-lb casing, kickoff points, liner tops and depths. The MCTD helped Synergy reduce pump-down water consumption 26% compared to the other wells and also reduced its overall cost of water. More importantly, it helped conserve a precious resource in this region.

Charges aid proppant placement

In horizontal wellbores, guns lay on the bottom and usually produce larger perforation entrance hole diameters on the low side of casing than on the high. Because frack fluids tend to flow more through the bigger holes, stimulation pathways can be unpredictable and uneven once they hit the formation.

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% reductions in breakdown pressures and up to 3% reductions in treating pressure on these stages.

Halliburton also averaged the amount of proppant placed in all stages shot with each type of charge. Difference in averages: 4,650 lb more proppant was placed in the MaxForce-FRAC stages of one well and 4,635 lb in the other—both 3% increases. These benefits can be attributed to more consistently sized perforations produced by MaxForce-FRAC charges throughout the 360 degrees of the wellbore compared to the competing charge.

Saves time, produces better results

Together, these new technologies helped Synergy avoid the cost of a second CT run plus associated standby charges for a frack crew. Faster running speeds also meant that expensive frack crews never had to wait on less expensive pump-down crews. Finally, the company 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.

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