As operators work to define the economic extent of Ohio's Utica shale play, a six-county area is lighting up the board.

The late afternoon sun glints off the Ohio River separating West Virginia from Ohio on a crisp autumn drive down Ohio Highway 7. Coal-fired power plants dot the silver shoreline every few miles, representing an industry—coal mining—that has historically buttressed the economies of this Ohio River Valley in Appalachia. The river also demarcates the eastern extent of Ohio's newest economic driver—the Utica shale—which could compete with coal as a fuel source for power generation in the region. It is certainly creating new jobs lost to the declining coal industry.

“Eastern Ohio is seeing economic growth and opportunity like they haven't experienced in decades,” says Tom Stewart, president of the Ohio Oil & Gas Association. “This is not hyperbole. The people there are very happy with what the Utica is doing for them.”

So are oil and gas operators with choice land positions. With several hundred horizontal wells drilled in the play, the Utica is no longer the new kid on the block, although it remains shy of being in development mode. It is, though, young enough to elicit still-unanswered questions: What is the extent of the sweet spot? Will the northern tiers prove as prolific as the southern? Is the oil window dead? Might the dry gas compete with Marcellus shale economics? How long before infrastructure catches up to impatient operators?

At the end of September, 36 rigs were working the Utica, 14 more than the prior year, according to Baker Hughes Inc. Activity is concentrated in a fairway paralleling the eastern Ohio border from Columbiana through Washington counties. The commodity flow here is saturated with natural gas liquids (NGLs) and condensate, boosting economic returns in the current pricing environment. As of August, 870 wells had been permitted in Ohio.

Coming off second-quarter results, Credit Suisse analyst Mark Lear said in July, “Momentum in the Utica has gained steam as a spate of impressive well results is proving the basin to be a legitimate resource play.”

Within this fairway, results have not disappointed. In August, privately held Antero Resources revealed its Yontz 1H well in northwestern Monroe County with a breathtaking 8,879 barrels of oil equivalent (BOE) per day 24-hour initial production (IP) rate (36% liquids). That followed Gulfport Energy Corp.'s Shugert 1-12H, about 10 miles southwest in Belmont County, with 7,482 BOE per day (44% liquids). While these results are at the top end, initial results generally exceed 1,000 BOE per day.

“It is still early, but a number of operators in the southern Utica have released initial type curves for the play, and the economics projected rival the sweet spots of the most prolific basins in the US,” said Wells Fargo analyst Gordan Douthat in a September report.

Magnum Hunter Resources' chief executive Gary Evans agrees. “We see this region generating some of our highest rates of return for new wells drilled, even during a sub-optimum natural gas and NGLs commodity price environment.”

Approaching cruising altitude

Gulfport Energy's four-well Clay pad sits on a knoll overlooking the tree-lined Piedmont Lake in Harrison County. Recently put into sales, the Clay 3-4H was reported to flow 1,019 BOE on average per day over a seven-day period. The flow makes an audible hiss as it speeds through the wellhead. The initial Clay well in January tested 2,200 BOE per day on a 24-hour rate.

Oklahoma City-based Gulfport has emerged as a Wall Street favorite to Utica-loving investors. The company holds some 136,000 net acres in Harrison, Guernsey, Belmont, Noble and Monroe counties, now regarded as the epicenter of the core of the play. Its seven rigs plying the play are second only to Chesapeake Energy Corp., active further north. By year-end, Gulfport expects to have some 50 wells producing in the Utica. It likes what it sees.

“I've been in the industry 30 years, and these are by far the biggest wells I've ever been associated with,” says Mike Moore, Gulfport president and chief financial officer.

While the company has shifted to reporting seven-day average sales results, earlier wells were reported on 24-hour IP rates, typically from 2,000 up to 7,000 BOE.

Today, wells are flowed on a managed choke program, a practice of restricting production rates to maximize reserve recovery. Combined with very strong wellhead pressure, the technique results in decline curves that don't decline for several months in the wet-gas portion of the play. “We are pleased by the shallow decline in pressures in each of the commodity windows as

Overleaf: The fourth well of Gulfport Energy's Ryser pad in Harrison County, Ohio, undergoes hydraulic fracturing. The first well, 1-25H, shut in and protected by the cage, tested at 2,914 barrels of oil equivalent per day. Facing page, roughnecks on Nomac Rig 311 set surface casing for Gulfport Energy's Family 2-32 well, in Belmont County, adjacent to Interstate 70.

the wells continue to produce,” he says.

Gulfport type curves model an estimated ultimate recovery (EUR) for wet-gas wells of 3.1 million to 3.9 million barrels of oil each at a $9.5-million well cost. That equals a payout of just five to seven months.

“Certainly, the wet-gas window has incredible returns,” says Moore, “and the condensate window is just a little behind that.” Condensate well EURs come in at 1- to 1.5 million barrels for a 50% to 275% return.

The company's longest producing well at just over a year, the Wagner, is performing within that type curve. By the end of the third quarter, Gulfport should have about 20 wells online, producing some 12,500 barrels a day.

Further, the company anticipates hooking up another 25 to 30 wells in the fourth quarter, for a year-end exit rate of approximately 40,000 BOE per day.

Gulfport has centered its drilling activity where midstream partner Markwest Energy Partners is concentrating new facilities and gathering lines, particularly its Cadiz processing plant in southern Harrison County. Admittedly, the drilling plan to date has been paced to match the infrastructure buildout, slowed somewhat by pipeline permits and rights of way earlier in 2013.

“We became more geographically focused so we could leverage off those infrastructures in place,” says Moore. “You don't want to get too far ahead of your infrastructure. Fortunately for us, those are the areas with the best returns.”

Multiple-well pad drilling became the model, allowing more time to get gathering lines to the sites while avoiding stranding single wells unable to get production to sales quickly. “We do not want to be in a situation where we drill and frac wells, and shut in wells, for an extended period until the pipeline gets to us,” Moore says.

Markwest's Cadiz facility can process 125 million cubic feet (MMcf) per day, with Gulf-port as its anchor customer, with another 200 million to come online by mid-year 2014. Its Seneca processing facility currently under construction is due online by year-end with 400 million of capacity, adding another 200 million by mid-year. And where other operators find themselves in a hurry-up-and-wait scenario for take-away capacity, Gulfport believes its bottlenecks are distant memories.

“We are not constrained in any way by processing or take-away,” says Moore. “By June of next year, Markwest is going to have 1 Bcf (billion cubic feet) of processing capacity available to us and other operators.” Gulfport's typical completion recipe involves a 7,500-foot lateral, hydraulically fractured at 250-foot intervals using approximately 500,000 pounds of sand per stage. Slickwater has replaced gel fracs.

The company is also testing downspacing from current statutory spacing of 1,000 feet. On its Boy Scout pad, Gulfport drilled two additional wells, one 600 feet and the other 800 feet from the original two producing wells, with positive results. After initial communication of the frac fluids between the wells, the two older wells reverted back to where they were, and the two new wells appear to be producing in line with the type curve.

“Once the wells cleaned up, we're not seeing any communication between the four producers,” Moore says.

Now, the Darla pad, currently drilling in Harrison County, will put downspacing to the ultimate test, with the intent of forcing the wells to communicate. The pad will accommodate three wells in a fanned pattern, with the heels 325 feet apart, and the toes 1,300 feet apart. Chemical tracers injected during completion will illustrate exactly where the wells begin communicating. “We're trying to push the envelope,” Moore says. “We want to know at what point those chemical tracers cross over into other wells.”

Before downspacing at 160-acre spacing, Gulfport has identified 900 drilling locations. With downspacing, that could double. “That has a direct correlation to the amount of reserves we can book,” he says.

Gulfport will spend about $500 million this year on its Utica program, 90% of its overall budget, and that number will increase in 2014 as it plans to run seven rigs the entire year. At that pace, Moore anticipates upward of 80 wells to be drilled next year.

“Our growth is related to the Utica,” says Moore. “We're a lot further along than we were 12 months ago.” And while challenges remain, “they're much smaller than they have been.

“The Utica is a transformational asset for Gulfport.”

Southern trending

As geology goes, the Utica shale is present across several states, from West Virginia through Quebec, Canada. But oil and gas operators have found the Point Pleasant sub-member of the Utica, present in eastern Ohio, to hold the most accessible resource. “The Point Pleasant unit is prolific,” reports Wunderlich Securities analyst Irene Haas. “It is carbonate-rich with higher porosity, permeability and brittleness. The real productive interval is the Point Pleasant below the Utica shale.”

Chesapeake Energy led the charge to open the Utica-Point Pleasant, cornering the market in Carroll and Columbiana counties. The company has drilled 350 wells—accounting for 70% of the drilling in the play to date—with more than 100 on production. Chesapeake projects wet-gas EURs of 5- to 10 Bcfe, and has 10 rigs running.

Operators such as Halcon Resources, Range Resources and Hilcorp Energy Co. are testing the concept as the formation trends northeast through Ohio and into northwestern Pennsylvania, but data points are sparse. One well, Hal-con's Kibler 1H in Trumbull County, Ohio, shows promise, with an initial IP of 2,233 BOE per day (75% liquids). The company has nine wells drilling and completing across the northern Utica play.

But no doubt remains about the productivity of the Utica-Point Pleasant south of Carroll. The Ohio Oil & Gas Association's Stewart considers the known Utica sweet spot to encompass a six-county swath: Carroll County, the most heavily drilled, through Columbiana, Harrison, Belmont, Guernsey, Noble and (hopefully) Washington. He anticipates the productive sweet spot to widen east to west.

“We hope to see this touch the eastern side of Morgan County as well, and I hear operators are seeing outstanding wells in Morgan County, although dry gas.”

“We've been watching the Utica-Point Pleasant play for two years now, and a clear trend is emerging,” said Haas in a September report. “The best wells are lining up like a string of pearls leading us to Washington County,” where Magnum Hunter and PDC Energy hold sizeable positions. “The next hot spot will be Washington County.”

To put an exclamation point on the prospectivity, the play's first-mover, Chesapeake founder and former CEO Aubrey McClendon, via his American Energy Partners start-up, announced at press time he has acquired in excess of 100,000 acres in the southern extent, with $1.7 billion raised and plans for a minimum of 12 rigs in the next three years.

Accelerating the plan

PDC Energy entered 2013 intending to stick its toe into the Utica pond, and along the way found the water quite inviting. “Our toe is not in the pond anymore,” says PDC executive vice president and chief operating officer Bart Brookman. “We're in this. We're swimming.”

The Denver-based E&P company lives and breathes Wattenberg Niobrara, but a one-rig Utica evaluation program on 46,000 net acres concentrated in Guernsey and Washington counties struck pay dirt. Its first well, Onega-Commissioners #14-25H, with a 3,900-foot lateral and just 13 frac stages, in Guernsey County, tested 1,796 BOE per day on a 24-hour rate (56% condensate; 23% NGLs). Its second well, Detweiler #42-3H, also with a 3,900-foot lateral and 13 frac stages, tested 2,197 BOE per day.

Wasting no time, in March PDC nearly doubled its capex toward the play to $96 million, extending the rig through the year with the intent to spud 11 wells in 2013.

“We liked the results. Once we determined some initial rates, pressure data and the liquids window, we quickly accelerated our budget. We have to give this play enough time and capital to really define the opportunity,” says Brookman.

Following its first two wells, the company released a projected type curve in April with a range of 500,000 to 750,000 BOE EURs.

Since, PDC has drilled two more wells on the Detweiler pad, two on the Commissioners, and three on Stiers, with 5,000-foot laterals all in its northern region. Reported results are pending. The three Stiers wells are producing on choke into a low-pressure system, waiting to be tied into a high-pressure pipeline. Brookman confirms the producing Stiers wells “are performing well, by my standards.”

The opportunity set includes northern Washington County as well, where a full 75% of PDC's acreage lies, as well as even higher hopes. The first horizontal test in this area, PDC's Garvin #1H, was drilled with a 4,800-foot lateral and 20-plus frac stages, followed by its Neill #1H with a 6,000-foot lateral and more than 30 frac stages. At press time, each was completed and resting, with no reported results.

“We're encouraged by the geological data from those wells,” he says. While the Point Pleasant formation thins slightly, natural fracturing makes the reservoir attractive. “The data point to this being a candidate for strong economics.”

While it is early and production numbers are lacking, he is confident these southern region wells will honor the published type curve. “The high end might become the low end,” Brookman says. “If the Garvin well performs anywhere near where we think it will, you'll see a concentration of our drilling program move to the southern acreage. We're going to chase the best rock we have.”

Well costs are running $8- to $9 million.

PDC, like other producers, has been a victim of the unpredictable and sporadic infrastructure buildout. Its Guernsey County wells were either shut-in or choked back and flowing into a low-pressure system until late July, waiting on pipeline or compression station issues to be resolved. Its Washington County wells are set to flow into the new Blue Racer high-pressure system beginning in October.

“We've had some delays in pipeline connections, and that's been disappointing. But I don't think it's going to impact the productivity of our wells—it's just a matter of timing. It's not affecting our drilling plans.”

He anticipates midstream capacity will align with PDC's deliverability by early first-quarter 2014.

PDC plans to exit 2013 with nine Utica wells producing. Results from these as-yet unreported wells will determine whether PDC decides to add a second rig targeting Utica. That in turn will determine whether its budget is closer to $200 million or $100 million. The former seems more likely. “We are strongly evaluating the possibility of adding a second rig.”

Across the West Virginia line, PDC also sports a one-rig Marcellus shale program focused in Taylor, Barbour and Harrison counties. These wells yield 6- to 9 Bcf EURs, yet the Marcellus program is falling behind the Utica, sullied by its dry-gas economics, says Brookman.

“The Marcellus play has tremendous economics at $4.50 gas, but at $3.60 we're drilling for 20% returns. We love the play long term, but it's not going to compete for capital with the Utica, given we have liquids in the Utica.”

Brookman confirms the Utica is a key component to the company's production growth. “It is quickly evolving to compete for capital,” he says. “The returns on drilling can equal and compete with returns on the Niobrara.”

Dry gas competes

Gas is not always a bad word, according to SunTrust Robinson Humphrey analyst Neal Dingmann, particularly as it relates to the emerging Utica shale dry-gas window on the east side of the play along the Ohio, Pennsylvania and West Virginia border.

“It appears that the rate of the Utica gas is so big, that even these can be materially economic,” Dingmann said in a September research report, noting valuations for Utica dry-gas acreage have increased to around $9,000 an acre. “We look for even dry-gas wells in the play to generate returns over 100%.”

Says OOGA's Stewart, “Producers that have drilled in the dry-gas window tell me they are outstanding wells. You are going to see people develop it.”

Gulfport is testing the concept with its Irons well in Belmont County. It was expected to be online by press time. “We think the economics in the dry-gas window are also going to be very good,” Gulfport's Moore says, noting that the formation is overpressured here, which should deliver big volumes. “We have high expectations for that window. We think it's going to be as good as the sweet spot of the Marcellus.”

“The dry-gas window has taken a back seat, but should generate very attractive economics, in our view,” said Wells Fargo analyst Gordan Douthat in a September report. He points to Gulfport's Stutzman well that tested at 20 MMcf per day as an example, and he projects EURs of 15 Bcfe on the low end. “We believe EURs and ultimately returns in the dry-gas window of the Utica have the potential to compete with the neighboring Marcellus,” he said.

Mike Kelly, Global Hunter Securities analyst, said in July, “Confidence is gaining that the dry-gas portion of the Utica will post EURs competitive with the core of the Marcellus—10-plus Bcfe wells at a cost of $6 million per well.”

But is anyone else interested in drilling Utica dry gas? “It's happening right now,” according to Magnum Hunter's Evans. He is aware of 10 wells currently drilling in Monroe and Noble counties. “With dry gas, you don't have to worry about processing economics—you just tie it in and it flows.”

To the point, most observers aren't aware that the major oil companies are working in the Utica, he says, referencing ExxonMobil, Chevron and Shell. “They're in our backyards, and they love the dry gas.”

Big bet newcomer

Houston-based Magnum Hunter Resources traded its Eagle Ford position for a better opportunity in the Utica, selling 19,000 South Texas acres in April. In addition to its core Bakken and West Virginia Marcellus anchors, it sees ample upside in the Utica.

“We've made a strategic decision to significantly enhance our position in the Utica,” says Evans. “We are growing this as a new third leg of Magnum Hunter. The Utica is extremely exciting to us.”

Scale and economics were the primary motivating factors that caused Magnum Hunter to move out of the Eagle Ford. “We will see EURs in the Utica possibly double or more than what we previously saw down in the Eagle Ford. Pure economics is the reason we sold the Eagle Ford and moved into this region. We see returns being significant, in some cases in excess of 100%.”

SunTrust's Dingmann likes what he sees. In an August report, he said, “The company is on the verge of setting itself up to be one of the premier Utica players.”

By completing four acquisitions over the past three years, including one from Chesapeake, Magnum Hunter has quickly collected more than 88,000 net acres in Noble, Monroe and Washington counties, and essentially controls northern Washington County, according to Evans. “We believe this play goes farther south than everyone believes,” he says. “We think our bet is going to pay off pretty well for our shareholders.”

With 10 planned wells, the Farley pad in Washington County near the Noble County line is the company's first effort here. It was drilled and cased in August, is currently completing, but awaits pipeline hookup in early 2014. “We typically do not drill a well unless pipeline is there or on its way, but we wanted to test the acreage in this area,” he says.

Yet some 60% of Magnum Hunter's acreage lies in the dry-gas phase, which is just fine with Evans. “When you can produce dry gas at 20 million—maybe 30 million cubic feet a day—that competes very favorably with any oil well in the US,” he emphasizes.

Although Magnum Hunter has yet to test a dry-gas well, he draws these volumes from nearby offset wells.

Magnum Hunter in September hedged natural gas at $4.03 per Mcf. “At 30 MMcf per day, we are making a 160% rate of return. We believe a Utica dry-gas well in eastern Ohio will prove to be as competitive if not better than a Susquehanna County dry-gas Marcellus well in Pennsylvania.”

Magnum Hunter spudded its first dry-gas well in Monroe County on the West Virginia border in September. The Stalder pad is designed for 18 wells, 10 targeting Marcellus, and eight the Utica. He expects this one and one wet Marcellus well on the pad to be put into sales by year end. Then Magnum Hunter will jump the Ohio River.

“We're comfortable drilling the first Utica well in Tyler County, West Virginia,” he says, calling it virgin territory for the Utica. “There is not a reason in the world the Utica is not going to work in the western portions of West Virginia. I don't know how big those wells could be, but we're going to find out before the end of the year.”

Regarding take-away capacity, Magnum Hunter is in an advantaged position with its Eureka Hunter Pipeline subsidiary, with 90 miles of pipe gathering from its operations in the wet Marcellus and now expanding westward into Ohio. With the exception of the Farley pad to the west, Magnum Hunter plans its pads within reach of its midstream system.

Evans indicated the company could deploy up to six rigs in the play next year, pending approval, with eight new pads already prepared and pipeline on the way.

The Utica program will become the company's biggest growth asset, he predicts. “None of us yet know the magnitude, but all indications are that it's bigger and better than we ever dreamed. If it's as big as we think it is, we've got $3 billion worth of drilling to do.”

Altogether, with no production yet to show, it's a big bet, he says. “I'll know for sure at the end of the year when the fat lady sings.”

Utica oil rests

Where Utica condensate, wet gas and lean gas are gaining momentum, operators in the oil window farther west are packing up rigs and going elsewhere.

Magnum Hunter's Evans, who is not afraid to call a spade a spade, is clear on his opinion. “We don't like the oil side,” he declares. “It lacks pressure, and if you don't have pressure, there is no natural way to get the oil out.”

Eclipse Resources chief executive Ben Hulburt shares a similar viewpoint, although he holds hope for future upside on the private company's 135,000 acres there. “We frankly don't see a lot of potential at this point,” he says. Early results in the oil window from other operators have not been very attractive. “Until we see some sign that the reservoir pressure is sufficient to push out the oil, it's not something we plan to pursue.”

OOGA's Stewart, though, is not ready to concede the play. “We all know that there are good oil saturations in the Utica shale there,” he says, “but it gets shallower, so you don't have as good bottom-hole pressure, or the permeability, as in the Point Pleasant.”

He notes the 50,000 conventional wells drilled through the Utica to other formations that showed oil saturations in the mud logs. He references one well still in production today in Fairfield County, initially targeting the Rose Run, that hit a natural fracture in the Utica and “took off.”

“What that tells me is that we have good possibilities in the middle of the state in the Utica.”

He gives kudos to Devon Energy Corp., “the bravest of the brave,” for testing the concept in multiple counties before declaring the oil window of the Utica didn't meet its objectives. He's quick to add, “That doesn't mean it doesn't meet other people's objectives, and Devon said they still think that acreage is prospective.”

PDC's Brookman sees Utica oil this way: “It's going to be a different animal. There will be greater challenges because of the lower GOR (gas-to-oil ratio) of the rock.”

PDC has obtained data on the few wells that were drilled on the oily side of the play, “which I wouldn't say were horrible, but they just provide additional challenges,” he says. PDC has no plans to test the oil window in the upcoming year. “We haven't given up on it, but we're going to be cautious. More technical evolution is needed.”

The oil window needs more innovation, Stewart agrees, which the oil and gas industry is well known for. Propane and gas-assisted fracs are part of the conversation, as are better methods of propping the fractures, he says. “It's all about permeability. Somebody will figure that out.”

Gearing up

With the acquisition of The Oxford Oil Co. this summer for $650 million, Eclipse Resources more than doubled its position in the wet-gas core of the Utica with 90,000 acres, and propelled itself into the top five acreage holders in the southern extension of the play. To date, Eclipse has participated in 18 wells with operators such as Antero Resources, Hess Corp., Chesapeake Energy, Gulfport Energy, Consol Energy and Carrizo Oil & Gas.

“We define the core as portions of Noble, Guernsey, Harrison, Monroe and Belmont counties,” says Eclipse's Hulburt. “Early results are extremely encouraging. The results of the south have been almost two to three times the size of what we've seen in Carroll County and farther north.”

Hulburt theorizes that although the Utica deteriorates in quality moving south, it acts as a frac barrier to the underlying Point Pleasant, the superior rock, he says. Compared to the Utica here, the Point Pleasant has higher organic content, is more brittle, and features better porosity and permeability. Laterals are steered into the bottom third of the 110-foot-thick zone with the intent to keep the fractures contained to the Point Pleasant.

Eclipse shares interest in 10,000 acres with Antero. The State College, Pennsylvania-based company owns a 20% to 30% interest in Antero's Miley, Wayne Miley and Sandford wells, with IPs of 3,000 to 5,000 BOE per day. These were just recently put to sales. “Initial rates have been very attractive,” Hulburt acknowledges.

Eclipse is running two operated rigs in Monroe County, within the dry-gas window of the Utica, where it holds an additional 20,000 acres. Results of its first operated Utica well, on the Tippens pad, are “extremely encouraging,” he says. When tested on a 26/64-inch choke, the well flowed 19 MMcf per day with more

than 5,000 pounds of surface pressure. “Although it's dry gas, we think it's going to be an exciting area.” It's scheduled to be put into sales in early November.

Wells today cost about $10 million with a 6,000-foot lateral. He anticipates the EURs to be in the neighborhood of 10- to 15 Bcf per well, yielding a 40% rate of return. “We like the returns,” he says. “It's not as high as the wet-gas region, but it looks attractive to us. We believe the EURs could be similar to what you see in northeastern Pennsylvania.”

A second well targeting the liquids-rich Marcellus/Geneseo combination has also been drilled on the Tippens pad. Hulburt says this window will be a dual-zone development. “It's another zone we're excited about. It's not the focal point that people want to talk about today, but I think it will create attractive returns.”

The first of Eclipse's two rigs will move into the Harrison County wet-gas window by year end to begin drilling 15 wells, and the second rig is to focus on Guernsey and Noble counties by early 2014. “2014 will be heavily weighted toward liquids, but we will continue drilling in the dry-gas areas as well.”

He projects EURs of 600,000 to 1.8 million BOE per well in this region.

The only window Eclipse is shying away from, he says, is the oil window, where the company has 135,000 upside acres courtesy of the Oxford deal.

Eclipse is planning to scale up to five rigs by the end of 2014, with an estimated $500 million budget. To handle the increased pace, Hulburt recently added two former Chesapeake Utica veterans to his staff: Marty Byrd as vice president of land, and Oleg Tolmachev as vice president of drilling and completions.

“As Chesapeake has reduced its staff, that's been a blessing to companies like ours,” he says. “It brought us up the learning curve much quicker.”

Add to that the hiring of Matthew DeNezza as executive vice president and chief financial officer earlier in the year, and whispers of an IPO emerge. Is an IPO likely? “It's a possibility,” Hulburt says, one of several potential exit strategies. “Certainly the public markets are valuing the Utica very attractively—I think rightly so.”

NO REST FOR THE HURRIED

Nothing like dropping $10 million into a wellbore, then waiting an extra two months to begin producing cash flow. Such is the case en masse for Utica operators forced to “rest” their wells before hooking up to production. It's just the way it is.

Resting wells is a practice of waiting 30 to 60 days before producing them to allow the formation to absorb the hydraulic fracturing fluids. Early industry wells that were produced immediately were disappointing, which was believed due to the fluid absorption competing with the hydrocarbon flow.

Gulfport Energy now believes it has potentially overcome the need to rest wells, with its latest Wagner, Lyon and Clay wells put to sales with no resting period—and no noticeable falloff in productivity.

“We're encouraged by these three wells that we brought on without resting,” says Michael Moore, Gulfport president. “We're not seeing any material differences between these wells and other wells in similar parts of the play with a 60-day resting period.”

Why the difference? Slickwater fracs over gel fracs. Moore is making an educated guess, but he postulates that residue left behind from the gel might close off the microscopic pores of the rock, inhibiting hydrocarbon flow.

“Our goal has been to find a way to shorten or eliminate the resting period, and we think slickwater is the way to do that. Those wells seem to clean up quickly and produce well.”

Although Moore won't declare absolutely that resting is history, thus far the results seem consistent across the commodity windows, from condensate to leaner gas.

Gulfport is moving forward with slickwater fracs for all its wells, and is testing shortened resting periods side-by-side on multiwell pads. “If the slickwater can eliminate the resting period, we can get our wells on 60 days faster than in the past.”