SHREVEPORT, La.—The Haynesville Shale basin has re-emerged as one of the premier gas plays in North America. Although not on par with the Marcellus/Utica, the Haynesville is slowly building back up to the days when it produced more than 10 Bcf/d, reaching 8.3 Bcf/d in March, according to the U.S. Energy Information Administration.

Like its shale brethren throughout North America, production gains in the Haynesville can be attributed to enhanced completion designs and smarter production management strategies. Discussing these trends at Hart Energy’s recent DUG Haynesville conference were Dick Stoneburner, managing director and retired president, North America Shale Production Division, BHP Billiton Petroleum Ltd., Pine Brook Partners LP, Charles Goodson, president and CEO, PetroQuest Energy Inc., Jason Simmons, advanced technologies lead, Baker Hughes, a GE company, and Neil Modeland, business technology manger, Halliburton.

Among a range of topics, the four addressed choke management strategies, the popularity of slickwater fractures and which metrics offer the best indicators for a well’s performance.

Choke management strategies give companies flexibility in their production operations, from drawing down a reservoir quickly at the onset of production, or tapering off flow to extend the life of the well. Simmons said choke management strategies are dependent upon investor expectations and the goals of the individual operators.

“Choke management really comes down to company strategy,” he said. “That IRR [internal rate of return] is really the most important number, and it goes back to what the company strategy is. Are you going to get your best IRR by unleashing the well and just trying to take it down as quickly as possible, or is it better to wait and slowly bring it on?”

Addressing which metrics are best used to gauge a well’s success, such as EUR, or short-term initial production (IP) rates, Stoneburner said he prefers measures that indicate actual production.

“An EUR is a really subjective commentary,” he said. “I want to see 30-, 60-, 90-, 120-day [IPs]. I want to see real production, and really not what the EUR is, but a relative timeframe that says ‘Okay, this well will actually produce this much over this period of time,’ and then I can make a relative judgment as to what is the relative productivity.”

Goodson said PetroQuest, which operates in the Cotton Valley, typically gets a sense of its EUR after three months of production.

“With the Cotton Valley, which is a different animal than the Haynesville, we’ll see our peak rate probably after 10 to 30 days, maybe 40 days because of the water,” he said. “Then we’ll look after 90 days and we’ll start seeing that [decline], and that will give you an early indication of what your EUR is going to be in one of these wells, whether it’s 6 bcf or 12 bcf.”

Simmons said 24-hour IP rates might not correlate well to EURs, but in the Haynesville, production figures after six months or even one year after a well comes online are often the best indicators of a well’s expected production.

“That 24-hour IP is really great for press releases, but to really get a good data point to correlate back to either IRR or EUR, you’re looking at three months or six months or even 12 months depending on what area you’re in,” he said.

Modeland said operators making the decision to cut back on costs during the downturn was a key factor in the re-emergence of the Haynesville as an attractive economic opportunity.

“We wouldn’t be here talking about the Haynesville if two years ago during the downturn we decided to strip costs out of our completions,” he said. “We had to say ‘The only way I’m going to get this economical in this environment is to actually push costs. I’m going to tighten my stages, I’m going to put more stages, more cluster and more sand in [the well] and then I’m going to drill longer laterals.’ So, [operators] are putting that investment higher on the wells and getting an EUR that’s an acceptable rate of return.”

Like most other North American shale plays, operators, the panel members said, are primarily relying on slickwater fractures while occasionally using alternatives like gels or ceramics in special cases. Goodson said PetroQuest completes its wells with “strictly slickwater” with 100-mesh sand, which have resulted in improved fractures.

“Even before the industry downturn, a lot of clients were already moving to slickwater and they were already experimenting with very high proppant loading designs,” Simmons said. “What we’ve seen recently is anybody moving away from that design, there’s probably some well issues, some geology issues, and they need to control their facks a little better.”

In cases where slickwater is more difficult to place or in HP/HT wells, operators in the Haynesville have occasionally turned to gels or ceramics.

Stoneburner said among the early Haynesville wells his company fracked ran gel fracks, which resulted in poor production.

“The reservoir didn’t like it,” he said. “So, you can pump all the sand in the world [along with] a cross-linked gel in the Haynesville, you’re going to make a crappy well. When you really need to place that last component of sand, using some gel is a good idea, just not to be there for four weeks pumping a job.”

Brian Walzel can be reached at bwalzel@hartenergy.com.