Long-awaited exports from the nearly complete Sabine Pass LNG plant are expected to commence in January. Image: Cheniere Energy, Inc.

A handful of operators in the Haynesville/Bossier shale apparently didn’t get the message that gas is trading at sub-cellar prices, with prospects of a sustained recovery slim, at best. For these intrepid few, lower well costs have joined refracing and fresh injections of tweaked drilling and completion methodologies, to deliver higher returns and a resuscitation of sorts in a play that has been lingering on life support. This, even as once-entrenched players have either suspended operations or bailed out of the predominately dry gas Upper Jurassic play traversing some 9,000 mi² across northern Louisiana and East Texas.

“Our Haynesville results are proving to be both repeatable and predictable, which is a mandate in this market,” said Comstock Resources CEO M. Jay Allison in the third-quarter earnings call. “In fact, the Haynesville program is exceeding our expectations, where a $9-million drill-and-complete type-curve for a Haynesville well, at $2.50 gas, yields a 33% rate of return and at $3 gas yields a 55% rate of return.”

Along with sharply reduced well costs, underlying the modestly renewed interest are the impending exports of liquefied natural gas (LNG), and the new petrochemical and manufacturing facilities springing up along the Gulf Coast. And, unlike the Marcellus shale, which took over as the nation’s top unconventional gas producer, the Haynesville has a well-established takeaway infrastructure. “A lot of people forget that the Haynesville is right behind the Marcellus, and before the Marcellus came along, it was the Haynesville that was grabbing all the headlines,” said Todd Bush, principal of the Energent Group, a Houston marketing research firm.

COSTS IN LINE

The attraction of the Haynesville and overlying Bossier shales fell precipitously in the last decade, after wellhead gas prices began their stubborn crash from double to low single-digits. Operators could no longer afford the higher costs that accompanied the drilling and completion of typical 10,000-to-14,000-ft ultra-impermeable wells, with abnormal pressures and temperatures. “Remember, Haynesville gas is dry, so you also are not getting any liquids uplift, and, in fact, you are incurring some cost to clean the gas up to reduce the CO₂ level down to 2% or less, which is a typical spec, so there’s some processing or treating that goes on,” QEP Resources CEO Chuck Stanley said on Oct. 29.

Fig. 1. One of the five rigs that Anadarko is operating in the Haynesville region of its East Texas/northern Louisiana asset. Image: Anadarko Petroleum Co.

Nevertheless, along with hammering down well costs—in some cases below $8 million—operators say considerably longer laterals, steroidal completions and a growing refracing movement are generating flowrates and estimated ultimate recoveries (EUR) that make for reasonable margins. Houston’s EP Energy Corp., which restarted a Haynesville program in 2015, said at an average well cost of $7.8 million, its wells can deliver reasonable returns—even at gas below $2/Mcf.

While the Haynesville rig count has remained relatively flat this year, during the week of Nov. 22 it was up one, week-over-week, to 28 active rigs, according to Baker Hughes data, which documented 39 rigs working during the same period last year, Fig. 1. The latest rig tally is split nearly evenly between Louisiana (15) and Texas (13). As with the rig count, according to the best guesstimate of the U.S. Energy Information Administration (EIA), production has remained relatively flat in 2015 at just over 6.0 Bcfgd, Fig. 2.

Fig. 2. Historical gas production from 2007 through 2015. Source: U.S. Energy Information Administration (EIA).

Going forward, the Louisiana Department of Natural Resources (DNR) had issued 129 new Haynesville drilling authorizations as of Nov. 14, compared to 213 permits approved for all of 2014—a far cry from the 1,103 permits handed out in 2010. The picture is nearly the same across the border, where the Texas Railroad Commission (RRC), that state’s chief regulator, had issued 159 horizontal drilling permits by Nov. 10 within Texas’ delineated portion of the Haynesville. This compares to 220 drilling authorizations for the same 2014 timeframe. A sampling of long-standing operators shows that attention is turning more toward increasing output from existing wells.

2015 RECAP

Chesapeake Energy Corp. remains the most active operator, with six rigs running in its 387,000-net-acre leasehold for the remainder of 2015. The Oklahoma City-based independent says that it has reduced average completed well costs this year to $7.7 million, based on average lateral lengths of 5,000 ft with 14 frac stages, compared to $8.4 million last year, for 4,900-ft laterals. In the third quarter, Chesapeake, which this year drilled Haynesville laterals up to 10,020 ft, reported break-even costs of just over $2.50/Mcf.

During the quarter, Chesapeake’s net Haynesville production averaged 636 MMcfgd, down 5% year-over-year. The company placed seven wells on production during the quarter, compared to 14 in the same 2014 period.

In September, Chesapeake negotiated a fixed-fee gas gathering agreement with the Williams Companies that specifies placing 140 equivalent wells on production by the end of 2017. Chesapeake expects to run four to six rigs between now and then.

Fig. 3. Houston’s EP Energy returned to the Haynesville with a flourish after a three-year hiatus. Image: EP Energy Corp.

Reflecting the newfound interest in the Haynesville, EP Energy decided the time was right to return to active status after a three-year hiatus, Fig. 3. With 38,000 net acres held by production (HBP), EP, until this year had not completed a Haynesville well since second-quarter 2012. The Houston-based independent recently completed two wells with 4,500-ft laterals and super-sized completions, featuring 220-ft frac stage spacing with 2,700 lb/ft to 3,600 lb/ft proppant, resulting in 30-day production averaging 12 MMcfgd/well. EP also drilled and completed two wells with 7,500-ft laterals in the third quarter, with early production exceeding 20 MMcfgd/well. In addition, four refracs completed in the second quarter increased initial production seven-fold, EP said.

“I would say we are learning, real time, on how good those wells are,” said President and CEO Brent Smolik. “But, given what we have just seen in the 4,500-ft laterals and the 7,500-ft laterals, and using the new completions, it’s the best returns in our program. Even down to sub-$2, it’s well in excess of the cost of capital.” With drilling completed for this year, a spokesman said the company is evaluating the longer laterals and enhanced completions, and outlining plans for 2016.

Dallas’ EXCO Resources Inc. holds 97,800 net acres—prospective for both the Haynesville and Bossier shales—and is concentrating, for now, on developing the East Texas portion of its leasehold. The Texas acreage delivered 52 MMcfgd in the third quarter, up 30% from the previous three months, and 27 MMcfgd, or 108% higher, than the same quarter in 2014. The development program included three rigs that drilled four gross Haynesville wells and one gross Bossier well, including a company-record 21,289-ft, MD, well in Nacogdoches County, Texas.

“When we do re-engage (in Louisiana), we will pump larger stimulations and change the well spacing to four wells per section, or 1,320-ft spacing,” said Harold H. Jameson, EXCO V.P. and East Texas general manager. “We have additional potential in North Louisiana that we fully expect to unlock with larger stimulations and longer cross-unit laterals.”

In a sharp trend departure, Comstock has put activity on hold within its oily Eagle Ford acreage in favor of the Haynesville. Comstock’s 2015 plans call for 10 new wells on its 68,000 net acres, including eight that have been drilled with 7,500-ft laterals and hooked up to production, with higher-than-expected flowrates, the company said. “Restarting our development of the Haynesville has allowed us to increase our gas production 119% from our first-quarter rate,” said Allison, adding that between longer laterals and larger fracs, Comstock expects EUR’s of up to 16 Bcfg/well. Despite the longer laterals, the company said that total well costs have dropped from a high of $11.3 million to $9.6 million, and it expects 2016 drilling and completions to come in at around $9 million/well.

In the third quarter, Comstock’s Haynesville gas production grew 40%, year-over-year, to 146 MMcfd. The firm expects to average 150 MMcfgd to 170 MMcfgd in the final quarter of 2015.

XTO Energy controls a commanding 675,000 acres in northern Louisiana where, at last report, the Exxon Mobil subsidiary was running a single rig. No further information has been made available. Elsewhere, both BHP Billiton and QEP Resources have suspended activity for the time being, in their respective 239,000 and 50,000 net-acre leaseholds, which are wholly HBP.

ASSETS TRADE HANDS

On Nov. 13, Encana Oil & Gas (USA) officially sold its Haynesville assets to tightly-held GEP Haynesville LLC, a JV of GeoSouthern Haynesville LP and GSO Capital Partners LP. The $850-million acquisition gives GEP 112,000 net acres in the northern Louisiana fairway.

The Encana liquidation follows on the heels of Penn Virginia Oil & Gas LP’s $74-million sale of its prospective Haynesville East Texas assets. The September sale to newcomer Covey Park Energy of Dallas included roughly 32,600 net acres prospective for the Haynesville.

During the third quarter, Legacy Reserves LP of Midland, Texas, closed on its $440-million acquisition of Anadarko Petroleum’s East Texas Bossier gas play, including Western Gas Partners’ pipeline and gas-gathering network.

Prior to the sale, Anadarko controlled roughly 360,000 gross acres in its East Texas/North Louisiana portfolio, where it still plans to run five rigs and finish the year by drilling up to 60 wells. Excluding the now-liquidated Bossier play, the remaining acreage delivered 53,000 boed in the third quarter, down 11% from the previous quarter.

Fig. 4. Average well performance of Haynesville horizontal re-fraced wells. Source: Rystad Energy NASWellData.

In August, privately held Vine Oil & Gas, which Blackstone Energy Partners formed in early 2014, celebrated its first year in the Haynesville after acquiring 107,000 net acres in the Louisiana core from Shell. Vine has provided no information on its current activity focus.

REFRACING MOMENTUM

Operators point to older completions, combined with the typically high flowrates of original wells, as making Haynesville wells ideal candidates for refracing. The Rystad Energy analysis found that refracing increased exponentially, year-over-year, in 2015. Yet, it still represents less than 1% of the total number of wells completed in the play. Rystad analyst Artem Abramov documented 32 Haynesville horizontal wells that had been refraced through August. The average Haynesville refrac, he said, delivered 4.5 MMcfgd of incremental production in the first four months, equivalent to 50% of the original well performance at less than half the cost of a new well, Fig. 4.

Todd Bush, the Energent Group founder, says that while the firm’s database shows swings in production spikes, Haynesville wells, generally, have shown at least a ten-fold increase in flowrates in the first month after a refrac. Depending on myriad factors, including type of refrac, lateral length, as well as the types and volumes of chemical and proppant used, the Energent study found that the costs of refracing Haynesville wells ranged between $900,000 and $2.8 million, with the average falling around $1.65 million. Bush said a $1.75-million refrac job is economically viable at around $2.75/Mcfg.

“Definitely, the older completions increase the refracing interest in the Haynesville, where you have operators applying lessons learned from other plays,” Bush says. “Also, the Haynesville is attractive, because there is a lot known about it, and there are these deeper, high-pressure formations that can yield more gas, based on spending maybe $1 million to $1.5 million on a refrac.”

Using primary research and the proprietary data, Energent triangulated refrac wells across the Haynesville shale to uncover the operators and service companies involved in refrac programs, Bush said. “We took the original well cost, and then looked at the amount of chemicals and proppants, as well as the actual pumper being used, to basically project those costs to see who was getting the better returns,” he said. “We found a couple of operators that have more or less dabbled (with refracs) in the Haynesville, and a few that are clearly executing a strategy of taking a group of 10 or 15 wells, refracing them and seeing what kind of results they get.”

Fig. 5. Chesapeake has recorded a 700% jump in average 30-day production after refracing. Source: Chesapeake Energy Corp.

Count Chesapeake among the latter. In an August investor update, Chesapeake says a comparison of its refraced and original wells shows a 700% improvement in average 30-day production rates, Fig. 5. Post-refrac wells delivered average 30-day production of 3.05 Bcfgd, Chesapeake said, compared to 351 Mcfgd for pre-refraced wells, with a nearly two-month plateau of 3.2 Bcfgd. In addition, its refracing programs delivered more than 500% improvement in 30-day average flowing tubing pressure.

Energent, meanwhile, sees Haynesville refracing activity increasing between 20% and 30% in 2016. “If (gas) prices stay where they are, there could be more emphasis on refracing, as you can possibly refrac three to five wells for the cost of possibly drilling one well,” Bush said. “What we’re wondering, is that while the equipment is there, if interest picks up, will the frac crews be available?”

Comstock, for one, has backtracked on its plans of earlier this year to earmark $23 million for refracing up to 14 wells in 2015, after its first refrac boosted the targeted well’s flow rate eight-fold with a tripling of flowing pressure. Given the performance of recent offset wells, the independent has decided against any further refracs, at least for 2015.

NEW CUSTOMERS

For now, market-weary producers are looking at the expected January launch of LNG exports as hopefully nibbling away at some of the excess supply. Construction is winding down on Cheniere Energy’s Sabine Pass LNG terminal, with first production expected in December and exports to begin at the start of 2016. When all six trains are up and running, the Louisiana facility will have total export capacity of 3.8 Bcfgd.

The Cameron LNG consortium also plans to make a final investment decision in 2016 on whether to proceed with its Lake Charles, La., export terminal. Pending approval by the Federal Energy Regulatory Commission (FERC) and final sanctioning, the facility reportedly would have an LNG export capacity of 3.53 Bcfgd. 

Early obstacles drive Haynesville refracs

The timing of the Haynesville shale emergence, in tandem with daunting geological characteristics that posed intense headaches for those early stimulation jobs, ironically make it an ideal candidate for refracing, says Stephen Persac, senior technical professional for Halliburton, which at last count has conducted 21 refracs in the play.

Following on the heels of the graybeard Barnett shale of North Texas, the original completions in the Haynesville did not have the benefit of an extensive learning curve. “We didn’t know exactly how to frac the Haynesville horizontally, so there were a lot of missteps early on,” Persac said. “Those vintage wells certainly were not completed the same way they would be today.”

“Secondly, the Haynesville has some of the highest pressures and highest temperatures and is one of the worst shale formations to frac,” he said. “Many of the original fracs have been crushed—they have a lot of scaling—so a lot of the permeability that we had by putting those early satellite fracs in the ground is no longer there.”

All that, Persac said, makes Haynesville wells prime refracing targets. “The Haynesville has some unique characteristics that make it great for refracing. From a refrac standpoint, some of the things that hurt us before also make good reasons for going back and refracing those wells,” he said.

Persac said the Haynesville was one of the proving grounds for Halliburton’s multi-faceted ACTIVATE refracturing service. The technology was first applied in a Haynesville refrac job in 2013, and it has gone on to be a widely accepted alternative to effective, but risky, mechanical diversions. “Granted, whether it be coiled tubing or reworking the entire wellbore, you’ll be able to actually isolate and pump in the exact place you want to pump into. But, between getting the coiled tubing stuck, or even getting the casing down, there are a lot of risks.”

Todd Bush, principal of the Energent Group, which has developed an extensive multi-play refracing database, agreed, adding, “Mechanical diversion is a reliable way to open and close, but there are a lot of concerns over damaging the wellbore.”  

About the Authors

Jim Redden

Contributing Editor

Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.