After nine years and more than 3,000 wells, Southwestern Energy Corp.'s senior vice president of the Fayetteville shale division questions whether “harvest mode” accurately describes the company's phase of drilling in what most would consider one of the more mature resource plays. He outright dismisses the idea that the program is now a “cookie cutter.”

“We're in development mode,” says Jack Bergeron, “but we continue to learn new things all the time that enhances the value of our assets. It's an evolution.”

Houston-based Southwestern, a $13.5-billion company, is built on the Fayetteville shale. On the heels of pioneering successes by other explorers in the emerging Barnett and Woodford shales, in 2004 the company drilled its first Fayetteville shale well and was on its way to amassing its current 900,000-acre position in the heart of the play in north-central Arkansas. Excluding a large block of federal land, the company concentrates on 650,000 acres primarily in Conway, Van Buren, Faulkner, Cleburne and White counties.

Today, more than 70% of company revenue comes from the Fayetteville. It produces in excess of 2 billion cubic feet of gas daily, and has surpassed 3 trillion cubic feet of accumulated production.

And Southwestern's Fayetteville shale wells keep getting bigger. Even now, the program is a work-in-progress, as the company fine-tunes its practices to squeeze out every ounce of economic value from the play, a trait in which Southwestern prides itself. Surprises remain.

In third-quarter 2013, Southwestern placed on production two of the highest-rate wells it has drilled and completed in the play, the Ledbetter 07-16-12 14H in Conway County and Sneed 08-12 6-1H7 in Faulkner County, both near 10 million cubic feet (MMcf) of gas per day. In the related conference call in November, Southwestern president and chief executive Steve Mueller said the results were indicative of the company continuing to push the envelope.

“We look at every little point where there might be a bottleneck, and we try to get rid of it.” He told his team, “'Do all the things you think you could do to make it the best you can.' Now, you're seeing what the best-you-can is.”

These incremental improvements involve longer laterals, modified completions and refined flowback techniques. Initial production (IP) rates for the 89 wells drilled in the most recent quarter averaged 4.9 MMcf per day. Jefferies analyst Biju Perincheril, in a research note, commented, “Average IPs increased about 36% sequentially, and is the highest quarterly average since inception.”

Learning process ongoing

According to Bergeron, even in a play as advanced as the Fayetteville, cookie cutter doesn't cut it.

“One size doesn't fit all,” he says. With 1,300 square miles of productive reservoir, rock varies. “If you assume a cookie-cutter mode and do everything the same way, you leave some of that behind. If you treat it all the same, you'll get substandard results in some areas.”

Case in point, the shale in the southern portion of its acreage is deep and high pressured. But in some areas here, the wells are hampered by high water cuts, with some previously deemed uneconomic to drill. Yet, by serendipity of being shut in due to pipeline constraints, Southwestern discovered “resting” these wells for 10 to 30 days, similar to practices in the Utica shale, resulted in less water, thus higher IP rates by 30% to 40%, not to mention lower water-handling costs.

“In the area where we've applied the extended shut-in, the economics are tremendous,” Bergeron says.

Fifty-five wells have been tested using this method, with another 20 to have been placed on production in the fourth quarter.

Yet the resting technique adds no value to results in its northern acreage, which is shallower and at lower reservoir pressure. Instead, results here have improved by placing more sand and less water in the completions.

Other areas of the Fayetteville contain high clay content, and “clay content in the rock doesn't like fresh water.” Instead, Southwestern pumps saline water into these completions to improve economics.

Southern wells IP higher but cost around $4 million, while northern wells IP lower but at half the cost. Results, though, are trending up across the play in response to improved completions.

All about PVI

An astute observer might note that the Fayette ville shale is a dry-gas reservoir, without “liquid-rich” phases as have some other high-profile resource plays attracting capex. That means, in the present sub-$4 per Mcf gas-price environment, positive per-well economics are hard to come by. That's the perception, at least.

Southwestern measures all capital invested against a Present Value Index (PVI) of 1.3, including every well drilled in the Fayetteville. “We want to return 30 cents above every dollar we invest, discounted at 10%,” says Bergeron. “That's our hurdle rate.”

Even in 2012, when gas prices precipitously dipped below $2 per Mcf, Southwestern held to its 1.3 PVI hurdle rate. To do so, it tossed aside its game plan of delineating and testing, and high-graded its portfolio to drill its best wells first.

“At 2012 prices, we made money,” he says. “Now, we're still doing it the way we consider most efficient.”

While other operators have laid down gas-focused rigs nationwide, Southwestern has steadily kept a fleet of eight rigs plying the Fayetteville throughout 2013, with the expectation of having put an additional 450 wells online by year-end 2013. And for the first time, the Fayetteville produced positive cash flow, just shy of $100 million on the year.

That's in contrast to offset operators, including XTO Energy, a division of ExxonMobil Corp., and BHP Billiton Petroleum. Together with Southwestern, the three almost entirely dominate the play with a combined 2 million acres. But BHP has dropped all of its rigs in the Fayetteville. XTO retains one. No one else is drilling.

XTO spokesperson Suann Lundsberg told Oil and Gas Investor the company, which holds approximately 550,000 acres, is taking a longer-term approach to developing its Fayetteville acreage.

“We are currently operating one rig, and plan to maintain a fairly consistent drilling schedule,” she said. “The Fayetteville continues to be an important area for XTO within our Mid-Continent Division's operations.”

Why can Southwestern drill forward when others choose not? Simply, the efficiencies it has achieved make it the low-cost operator.

Economies of scale

Southwestern's lease operating expense in the Fayetteville shale is $0.84, achieved through economies of scale. “We plan to be efficient,” says Bergeron.

Well costs are down 21% since 2007, to $2.3 million on average. That's at least $1 million below what other Fayetteville operators are able to achieve, he says. “Our capital is 20% to 25% less than theirs, before vertical integration credits. Simply, the cost of doing business is less for us.”

Vertical integration is critical to achieving low costs, trimming some $380,000 from the cost of each well drilled, he says. Partly because of lack of available services in the early days of the play, Southwestern now owns its own fit-for-purpose rigs and two completions crews.

Due to the shallowness of the Fayette - ville—from 2,000 to 5,600 feet total vertical depth—Southwestern deploys super-single drilling rigs throughout the play. Most of the company's wells are now drilled on multi-well pads, and these smaller but nimble rigs can be skidded from well to well in hours rather than days. Re-entry to re-entry is six days, down 66% from 17.5 days in 2007, even while lateral lengths have nearly doubled in that time.

Following drilling the initial wells on a pad to hold the unit, Southwestern attempts to drill the remaining wells in only one additional visit to the pad sites, which usually accommodate four to eight wells, thus minimizing mobilization costs.

A new fleet of fit-for-purpose walking rigs are on order that can move with pipe in the derrick. “We think these new rigs could chop a day off of that,” he says.

Not counted in its rig numbers, Southwestern utilizes spudder “air” rigs to drill and case the vertical segments, again saving days on site for the bigger rigs.

Southwestern established a logistics operations center to synergize it operations, including movement of water, equipment and sand. The strategy has reduced truck loads per week from 13,000 to 5,000. “That has saved us millions of dollars over the last few years,” he says.

For water handling in particular. Getting frac water to sites and moving produced water from sites previously cost $7 per barrel. “Disposal of water was our single highest cost. Our goal is to handle water only once.”

Southwestern now recycles 100% of its produced frac water for new completions, further saving in disposal costs. Eliminating partial loads, along with water recycling, has pushed down water-handling costs to near $3 per barrel.

“Water is a valuable resource,” Bergeron says. “Every barrel that we don't re-use, in my opinion, hurts the environment.”

Another example of cost savings via economy of scale: Southwestern sources sand for its completions from its own sand mine on the Arkansas River in North Little Rock. “If you're drilling hundreds of wells a year, sand is a big part of your cost,” he says.

Being an early entrant in the best geological position doesn't hurt economics either. “We operate the best rock.”

Fine-tuning DC

Having “best rock” is a moot point if you don't intersect it. “It doesn't do you any good to drill a two-mile lateral if it's not in zone to propagate a fracture,” he says.

While it treats every wellbore and completion individually, Southwestern typically aims its laterals into the upper half of the average 260-footthick Lower Fayetteville member, a more brittle segment of the formation. To precisely hit the zone, the company created a drilling operations center, in which drilling engineers and operations geologists communicate in real-time, 24 hours a day, with the rig drilling supervisor.

“We've actually had to slow down our drilling engineers,” Bergeron says. “Now, we emphasize as a team to get that hole in zone.” The results are reflected in the past quarter's record IPs. “We took great attention to getting every well in zone as much as we could, so we can make every foot effective.”

The practice has significantly reduced sidetracks. “Sidetracks make your $3-million well turn into a $4.5-million well real quick. That hurts your economics.”

And because the rigs are owned by Southwestern, learned efficiencies are implemented across the fleet.

Average lateral length now extends beyond 5,000 feet, up from 2,700 in 2007, with some even longer. The record Ledbetter well featured an 8,500-foot lateral with 18 frac stages and 7 million pounds of sand. It cost $4.6 million. Such longer laterals had pushed up average well costs to $2.6 million at quarter's end.

Lateral length is determined by lease lines or geological barriers, as the Fayetteville is laced

Well costs are down 21% since 2007, to $2.3 million on average with faulting. “The more reservoir rock you contact, the more bang for your buck,” he emphasizes.

Completion techniques have evolved as well. The producer has eliminated what it considers unnecessary chemicals to reduce costs. “We inject water, friction reducer and sand, and that's about it,” he says. It is using less water and more sand as well.

Also, instead of utilizing coiled tubing, the company has reverted to drilling out the lateral with a workover rig. “It's going backward, but it's less expensive and we get a better drill-out rate,” he says, particularly on longer laterals.

The Ledbetter and Sneed well flow rates benefited from utilizing bigger production equipment, going to four-inch lines from three inches. Southwestern now constructs all of its wells with four-inch lines. “Any time you can bring value forward, it increases the economics of your well,” Bergeron says.

Upside in the Upper

On much of its acreage, Bergeron believes its completions effectively stimulate and produce from the Lower and Upper Fayetteville reservoirs. However, in some areas, the clay-rich Middle Fayetteville acts as a barrier to the upper zone, expanding and pinching off as it absorbs water.

In these areas, Southwestern has tested drilling and completing into the Upper Fayette - ville, about half as thick as the lower zone, with more than 30 wells to date. Two of the most recently reported wells produced 6.6- and 6.7 MMcf per day. The company estimates 120,000 acres are prospective for Upper Fayetteville, near the border of Van Buren and Conway counties.

Besides the Fayetteville, Southwestern sees opportunity in the Moorefield shale below in White and Cleburne counties.

“We think there's upside there,” says Bergeron, “but we have no idea how much. We're going to continue to look there.” He estimates the Moorefield is prospective on about as much as 150,000 total acres.

Cash-flow generator

The Fayetteville is now a cash-flow spigot the company can ratchet up or down. “We need to be flexible” to deliver what the company needs, Bergeron says of the division. “If it's production growth, we'll do it. If it's cash flow, we can do that.”

Southwestern will spend in excess of $900 million in the Fayetteville during 2013. At press time, Southwestern's 2014 budget and number of planned rigs in the Fayetteville were undetermined. However, in the third-quarter call, Mueller seemed to telegraph the company's intent was to maintain or increase—rather than decrease—rigs running, to shift cash-flow forward. “I don't think you'll see us significantly increase our rigs,” he said, implying no downsizing was in the works.

Mueller indicated seven rigs are needed to hold production flat, and at eight or nine rigs, “(production) will grow, but at single digit numbers.” At current gas prices, that will keep the same $100 million in positive cash flow feeding the coffers to fund its Marcellus growth program in northeastern Pennsylvania, and new ventures such as the Brown-Dense play.

Most rigs today are focused in Faulkner, Van Buren and Cleburne counties, the east and south sections of its holdings, where it has experienced the highest results. Bergeron notes, though, that Southwestern has had successes broadly across the play, and the company is always reaching into less proven areas to prove them up for the next year's program.

The company has identified 8,000 drilling locations in the lower Fayetteville, and expects to continue developing the field on 60-acre spacing. With 3,000 wells drilled, that leaves another two-thirds to go, equating to more than 10 years of drilling at the current pace. Opportunities in the Upper Fayetteville and Moorefield are upside. The field will continue to produce for 30 years, he anticipates.

“We've learned how to efficiently and effectively build an organization to carry out a project this big,” Bergeron says. “We plan to be in the Fayetteville a long time.”

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