PITTSBURGH—In the natural gas-rich Appalachian Basin, where companies are drilling laterals of more than 18,000 ft, proppant volumes are high and thoughts are constantly on economics, focus remains on perfecting completion techniques to get the most from each well.
“We push the limits of longer laterals but as we all know that comes with a risk—risks while drilling, running casing,” said Matt Weinreich, senior vice president for Laurel Mountain Energy, a Pittsburgh-based independent focused on the Marcellus, Devonian and Utica formations in Western Pennsylvania. “That risk is something that we need to factor into the economics. … The bang for our buck is higher proppant loading, and we have pushed the limits successfully in our initial ventures.”
Weinreich was part of a panel on completions during Hart Energy’s DUG East conference and exhibition in late June. Completions techniques and trends have been holding the attention of the industry as lateral lengths grow and techniques become more complex, with each operator tailoring their methods based on geology while keeping an eye on their neighbors. Methods used so far helped to push gas production to more than an estimated 28.5 billion cubic feet per day in June with further growth expected in July, according to the U.S. Energy Information Administration’s latest drilling productivity report.
Longer laterals, landing changes and more sand have resulted in more stimulated rock.
For example, Chesapeake Energy Corp. (NYSE: CHK) recently made changes to its completion methods that resulted in about a 65% increase in 30-day average daily production rates for the first six wells in its 2018 Utica Shale drilling program in Ohio, the company said in May during its first-quarter 2018 earnings release.
The company placed 10 wells on production in the Utica during the first quarter and ran two rigs. Chesapeake expects to place seven wells on production during the second quarter with plans to ramp up to 35 wells for full-year 2018. In the Marcellus, the company is currently running three drilling rigs and plans to place up to 50 wells for the year.
“When you look at 24-hour IPs, 30-day IPs, you’re taking a snapshot of what that well is producing compared to what it can produce in 20-30 years. Everyone looks at that information, but at the end of the day we all look at full cycle economics” to make sure set goals are accomplished and value is created, Patrick Finney, vice president of completions for Chesapeake and panelist, said during the conference.
Parent, Child Wells
Stage spacing and whether the well is a parent or child well are additional factors when determining completion methods, according to Finney. “You have to take all of that into account with economics to make those decisions,” he said.
On this note, well bashing—which happens when frack stimulation from a child well impacts a parent or legacy wellbore’s production—is something that should be understood before entering development mode, Finney added. In the Haynesville, where Chesapeake is also an operator, the company has seen a positive uptick in production based off a frack hit but the result has been negative in other places, he said.
Laurel Mountain was fortunate in that its acquired acreage had no existing laterals, Weinreich said.
“Infill wells will obviously be a big part of development going forward. … There’s probably more negative impact or at least a reduction in child well performances, but there are some interesting new technologies—[such as] pressure rejuvenation of parent wells—that I believe will contribute to at least some technological advances as well as capital efficiencies,” Weinreich said. “So those infill wells might not produce as much. But is there something we can limit on the design basis that would save capital upfront and make it somewhat more equal in terms of economics?”
Panelists seemed to agree that certain technologies can prove effective in completions, but they don’t work everywhere. Engineered proppants, such as resin-coated ceramic proppant, were among these.
Sergey Stolyarov, completion adviser for Baker Hughes Inc. (NYSE: BHGE), a GE company, talked about how ceramic proppant was pumped before market downturn in late 2014. But engineered proppants are more expensive than sand. “We switched over to sand. I think it’s just a price issue,” he said.
Chesapeake is not using engineered proppant at its Appalachian assets, but Finney said he believes there is a place and need for such proppants in certain formations.
Laurel Mountain, however, is using a bit of resin coat at the end of its stages for sand control and other purposes. The company is also experimenting with its use on laterals—one with resin and none with the other. The company is awaiting results, Weinreich said.
Using microseismic technology to aid in completions design was another area of discussion. Chesapeake uses it when possible but Finney admits that cost can be an issue, which requires working with a strategic partner.
Weinreich acknowledged microseismic’s benefits, particularly when it comes to gaining knowledge about stimulated rock volumes. But he said “as a small operator I’ll probably place my technology capital elsewhere. … It is a great technology but there are limitations.”
Stolyarov pointed out the work that still needs to be done, saying “We pump proppant but don’t know where it goes.”
When it comes to sequencing of laterals and zipper fracks, there doesn’t appear to be any magical application. But the topic is being discussed a lot at Laurel Mountain, considering there is only about 500 ft between two potential producing formations—Upper Devonian and Marcellus—the company is targeting. Weinreich said the company is studying how the two interact and whether reserves would be lost by not sequencing or zipper fracturing, which appears to be what most operators are doing in the basin because of their efficiency.
Diverter technology is another area of focus for some Appalachian producers to boost the effectiveness of stimulation by directing frack fluids to perforation clusters.
Chesapeake has tried several different methods, tests and loadings with different companies, Finney said. “Now we are just watching results to see how much it improved production results and pay for the actual product.”
Laurel Mountain is also evaluating the technology.
“Our interest is in a very simple concept of taking 150-ft stages and making them 300-ft with diverters and you’ll be able to monitor that immediately with proppant placed,” Weinreich said. “If you can place your planned proppant amount over the 300 ft, drop diverters and place an additional bound, I believe that will be a positive indication right away. We’re not there yet but we’re working toward it.”
Velda Addison can be reached at firstname.lastname@example.org.