Not so long ago—in geologic terms—a sea that covered much of the western US had a shoreline in New Mexico where the rock was named Gallup sandstone in the past century; the delta mud that encased it at this southern edge of the modern San Juan Basin was named Mancos shale. In time, oil and gas that were cooked in the fine-grained, Cretaceous-age shale intervals have migrated into the less-tight sandstone.

And that makes a play.

“When we pressure-pump our frac stimulation into it, we have a shale above us and one beneath us. We can't break above and below the sandstone, so all the frac energy remains within the targeted interval,” says Steve Natali, senior vice president, exploration, for WPX Energy Inc.

Recently spun out of Williams Companies Inc., Tulsa-based WPX has worked the San Juan Basin's many formations since 1983, ranging from the Fruitland coalbed and Mesaverde sandstones, which lie above Man-cos shale, and Dakota sandstone below. Its 159,000 net acres host some 3,300 wells, which hold by production nearly all of its leasehold.

In 2008, it took a new look at the basin, exploring the Mancos in the northern, dry-gas window in southern Colorado; there, the chalky Niobrara sits within the shale. “We had a significant acreage position there,” Natali says. “Gas was about $8 an Mcf [thousand cubic feet]. We were producing from formations above and below Mancos but, at the time, no one knew if the Niobrara member of the Man-cos could produce commercially.”

WPX drilled four vertical, science wells, taking cores. In 2010, it made two horizontals in two zones. “Those wells came on very strong—about 17 million cubic feet a day—but we

elected to choke them back to about 7 million to prevent damaging the formation.”

After three years online, estimates are each will make between 5.5- and 6 billion cubic feet (Bcf) of gas. But gas futures began tumbling in mid-2008, bottoming at below $2 by the spring of 2012. The Niobrara play in the northern San Juan Basin was put aside.

“It will be highly economic when gas prices recover,” Natali says. “We believe it's a multi-trillion-cubic-foot (Tcf) resource waiting to be developed based on these discoveries.”

Looking for a liquids play instead, WPX considered the wet-gas window of the Mancos shale itself.

“We thought, 'You can't move oil through the Mancos shale because it isn't permeable enough, but you could move wet gas or condensate through this shale. In the Eagle Ford, the wet gas is actually moving through the reservoir as a gas; as it comes up, it cools and the condensate falls out.

“It has to move as a gas because you simply can't move liquids through these tight shales at a very high speed.”

After some study, it was determined that the wet gas wasn't going to commercially move out of Mancos in the area.

“So we abandoned that effort,” Natali says.

Meanwhile, WPX looked at the 200-footthick Niobrara member of the 2,000-foot-thick Mancos at about 9,000 feet in the Piceance Basin in northwestern Colorado, taking core from a vertical and logging it. In late 2012, the company went in with a horizontal, 701-4 HN1 Williams GM, in Garfield County, bringing it on with 16 million cubic feet a day. In its first 10 months, it made some 2 Bcf and was still producing 3.5 million a day in early November from the over-pressured interval with a gradient of 0.9 psi per foot.

“That is the highest-flowing Niobrara well in the US We're offsetting it in several directions,” Natali says.

Three miles southeast, a second horizontal, 702-23 HN1 Williams GM, was landed higher in Niobrara where pressure is 0.94. It came on with 11.8 million a day from a roughly 4,900-foot lateral and 19 frac stages for the second-highest-initial-production (IP) Niobrara well. (Other top Niobrara producers are in the Denver-Julesburg and Powder River basins and are primarily oil, such as EOG Resources Inc.'s 2-01H Jake, which IP'd with 1,770 barrels a day.)

Although it is a gas producer, WPX is continuing to work the play as it estimates 20 to 30 Tcf equivalent of potential resource.

But it still sought more liquids production, particularly oil, to supplement its growing Bakken production.

It looked at the oily Mancos shale in the southern San Juan Basin. “Could we make a halo play at the edges of the existing Gallup sandstone fields? You have mounds of sand where it is thick in the middle and thins out to the edges. So we asked ourselves, 'Could we drill horizontal wells from the thickest part all the way out to the thin edges and get that remaining oil?' We decided that probably wasn't going to work.

“But, as part of doing that, we stumbled across this region that has very unique characteristics. It had been penetrated [in the past] but not really recognized for what it was.”

Looking at logs of many old, vertical wells that had traveled through Mancos on their way to Dakota, WPX found oil saturation and good porosity where the 150-foot Gallup section—instead of Niobrara—suddenly appears at about 5,500 feet along the ancient shore that may be some 60 miles long.

But the logs offered little additional detail. “They were just old logs. They didn't have high-quality, modern log suites at the time. People had drilled through the Mancos and didn't see anything worth testing based on the technology at the time. They moved on,” Natali

.

“The formation had been condemned by industry. A number of people told us, 'You're wasting your time out there. The Mancos will never give up anything commercially.'”

But what about the Gallup?

In four, modern, science wells—one in each of four townships—“we ran every log and did every study known to mankind. In one, we cored the entire Gallup sandstone. Our geologists and reservoir engineers estimated there are about 14.5 million barrels of original oil in place per section.”

Oil saturation is 65%. Effective porosity ranges from 9% to 13%. Matrix permeability is as high as 30 microdarcies; system permeability is between 10 and 100 microdarcies. The sandstone is primarily quartz with some clay, calcite and dolomite and a small amount of pyrite.

“It is much more like a conventional reservoir. It's a dirty sandstone, which makes it fairly tight and is why the vertical wells of the past were uneconomic, except in particular areas.”

Meanwhile, Calgary-based Encana Corp., with 176,000 net acres in the southern portion of the basin, brought on the Gallup discovery well, Lybrook H36-2307, with 445 barrels of oil equivalent (BOE) a day; first-full-month production was more than 8,000 BOE. Its subsequent Lybrook A03-2206 came on with 651 and made just under 8,000 in its first 30 days.

In January 2013, WPX quickly brought on its first horizontal in what has become a 31,400-net-acre position in the oil window with 488 BOE a day; its next three came on with between 623 and 1,004. The production: 70% oil and 30% gas with a Btu of some 1,300. By November, WPX had nine Gallup wells completed and producing, with IPs averaging 728 BOE.

Chaco 2306-19M 191H came up with first-full-month production of some 14,500 BOE; Chaco 2308-16I 147H, some 12,300.

Another well, Chaco 2307-12E 168H, made nearly 8,000 in just its first 13 days online—the fifth-best in the play among about 30 for which production details had been released by the state by early November. Of the top eight Gallup wells, WPX had four.

Four more were expected to be online by year-end for a total of 3,400 BOE per day for WPX from the new play. The horizontals—each involving some 9,700 feet of hole—were being drilled in 17 days, down from initial estimates of 28. Wells were costing less than $6 million; the 2014 target is $5 million or less.

Encana Corp., with more than 20 Gallup wells online, reports well costs of some $4.3 million and has ranked the basin as among its Top Five assets. It plans to spend some $400 million there this year—about $150 million more than in its successful, oily Tuscaloosa Marine shale play where wells cost more than $10 million each.

Houston-based EV Energy Partners LP has some 22,000 net acres in the area held by production from other formations. While drilling a vertical to Dakota sandstone in 2013, the company ran openhole logs and pulled core from Gallup. It planned in late 2013 to assess the horizontal potential of its acreage this year.

Birmingham, Alabama-based Energen Corp., which has more than 5,300 locations to drill in the Permian Basin, holds some 73,000 net acres within New Mexico's Gallup window. Its plans are to participate in two wells with WPX this year.

“We believe that this oil play is real …,” Irene Haas, equity analyst for Wunderlich Securities Inc., reported upon news of the WPX wells in 2013.

Natali says, “We created a hypothetical type curve going into this that was based on slightly lower matrix permeabilities than what we have actually encountered.” WPX also has a large Bakken position; for comparison, “while the Bakken is around 40 microdarcies, we are seeing up to 100 microdarcies in the Gallup.”

Gallup nomenclature has confused some, however; various media reports have called it a Niobrara play. Natali says, “Yes. Maybe I should explain that.”

The thick shale that was laid down in the seaway during the Cretaceous age is found in many basins and was given different names, depending on the basin in which a geologist was describing it. “For example, this shale is called the Eagle Ford in South Texas, the Mancos in the Piceance and DJ basins, and the Baxter in the Green River Basin.”

In some areas, the chalky Niobrara appears within the shale. “Along the southern edge of the San Juan Basin, that chalky member is replaced by the shoreline, Gallup sandstone. So, while the Gallup sandstone was laid down at the same time as the Niobrara member elsewhere, it is not the same type of rock.”

Plunging for paraffin

WPX plans 37 more Gallup wells this year and production of 8,400 BOE a day from the rock by year-end. All will be single laterals.

“We are in the throes of doing a great deal of reservoir modeling,” Natali says. “We are fracing the wells and watching how far from the wellbore they propagate. Because of the upper-and lower-shale frac barriers, it's very economic. All of the frac is propagating within the zone we are targeting. They are spreading out very nicely.”

The areal extent of the play and ultimate spacing remain undetermined. “We're going right now with four wells per section, each draining 160 acres. Microseismic says those wells should not interfere with each other or barely interfere with each other. But could we go to six wells per section? The answer will be in the modeling.”

The oil is sweet and light, averaging some 40 degrees in gravity—identical to Bakken production.

As for monetization, the basin differential is about $11.50 less than WTI. The Gallup wells are within about 10 miles of an oil-gathering facility at Lybrook. From there, it is put into a pipe to a refinery near the city of Gallup. “If we exceed the Gallup-refinery capacity, there is rail transportation to the East Coast, West Coast and Louisiana. We don't anticipate the kind of transportation constraint that was seen in the Bakken.”

WPX is completing its wells with natural sand rather than ceramic proppant, unlike its Bakken wells in which it finds 65% high-strength ceramic and 35% sand more effective. The Gallup-play recovery is estimated to be 9% of the oil in place. Estimated ultimate recovery is 336,000 barrels of oil and 1 Bcf of gas per well or 504,000 BOE.

Pressure in the sandstone is only 0.3 psi per foot; normal pressure is 0.43.

“That's another reason why oil shows were suppressed as people drilled through the

Gallup. There was nothing—with a normal-weight drilling mud—that would allow the oil to flow to the wellbore when they were drilling on their way to Dakota years ago.”

In addition to artificial lift to further heelp surface the oil, a solution the San Juan Basin team developed for another problem is providding an incidental boost. The problem: The oil contains paraffin. At about 500 feet from the surfaace, the wax cools and can, eventually, clog the well.

“We and our competitors were being held back by this paraffin problem. It is difficult to make money if you are constantly having to stop production, bring in a workover ring, cut out the paraffin, move the rig off and re-establish production. And using chemicals to remove the paraffin was equally cost-prohibitive..”

The solution: The WPX team is using a plunger system that, driven by the associated gas, thrusts down and up the vertical section, preventing the paraffin from cooling and accumulating and, instead, sweeping it as a fluid to the surface.

Bob Revella, regional vice president, San Juan operations, says, “When we're using the plunger in conjunction with the gas-lift ssystem, we have mitigated the paraffin problem at little to no cost and we've reduced our overalll lifting cost. The temperature is right for it to pprecipitate at about 500 feet. With this, we address it right there.”

Revella joined the company in the basin in 1996 after pipeline operator Williams put its E&P assets in a new business unit, Williams Energy Group, to grow it and other non-pipeline, energy assets. At the time, 87% of the company's 531 Bcf of proved gas reserves were in the San Juan Basin.

Revella says of the new Gallup play, “It is gratifying that we were able to work our way into this position in the basin because it's our backyard. It is the asset that started everything for us.”

Does the Gallup work farther south?

“There is potential but there are some questions,” he says. “We're working through that. As you move south, the Mancos and Gallup are shallower. The deepest part of the basin is north in that dry-gas window. As you move south, you start traversing up and out of the basin and eventually these rocks outcrop.”

Single laterals—rather than dual or more laterals—per well may remain the development method. “The productive section—about 75 feet—is not thick enough. One lateral (alone) appears to be touching the majority of the highly productive section.”

The well cost is competitive with other horizontal plays, he adds. “The rates aren't Bakkenstyle rates so it doesn't attract that much attention, but they're very good rates,” he says. “People may think it is a sleeper. 'It's the San Juan Basin.'”

Most of the basin is held by existing production; some government land is available and existing operators are working on getting that leased too. “Everyone knows there's not a lot of room for anyone else to get in here. It's down to those parties who are already in and have the deals in progress to get what's left,” Revella says.

“But the quality of the play—the economics of it—is something that might surprise some people.”

In fact, it is the company's highest-rate-of-return play, says Ralph Hill, WPX president and chief executive officer—trumping that of the Bakken, WPX's huge new Piceance Basin gas play and the Marcellus. Expectations are to spend some 85% of its 2014 capital budget on Gallup, Bakken and Piceance.

Hill says, “We are drilling under $6 million for 500 million BOE and we expect that to get into the $5-million range and that includes everything—facilities, hookups, everything. For comparison, the Bakken is in the $10- to $11-million range and 800 million BOE. The San Juan is drilled in less time and at less cost for the associated reserves.

“We are very happy to be in both plays. The Gallup has a better incremental return right now while the Bakken has bigger scale.”

As for scale, Hill would like to take WPX's Gallup position to 60,000 net acres.

“We still haven't mapped all of the sweet spot yet, but our people put us in the best area right off the bat.”

The company's reserves declined in 2012 as a result of cutting rigs due to poor gas futures. “We didn't want to drill into that environment,” he says. “I think it was the right decision, but it made us look like we didn't grow in our first year [after being spun out from Williams] on a total portfolio basis.”

But, in 2013, it grew its Bakken production by about 30% and expects to grow that further by between 30% and 35% this year. “And we saw an incremental increase in our gas production in the third quarter,” he notes.

WPX had 18 Tcf of proved, probable and possible reserves at year-end 2012. “That's before this Gallup discovery, which we hope will ultimately add 66 million BOE in time, and that's before the Niobrara discovery in the Piceance Basin, which could be 20 to 30 Tcf more as we prove up the play.

“We don't have to do anything except exe-

cute on our existing portfolio. We don't have to buy anybody. We don't have to buy any assets. Our assets are set for growth.”

Colorado's Spergen

Roughly 450 miles northeast, the dolomitic, Mississippian-age, Spergen oil formation was being made during the organic-rich Carboniferous era some 250 million years before Gallup, Mancos and Niobrara were being laid down.

By 2012, however, no one had drilled that deep—at about 8,000 feet—in the stacked pay of the southern Denver-Julesburg Basin in Lincoln County, far south of where 1,000-plusbarrel, shallower, Niobrara wells are being made now.

“We were the first in northern Lincoln County,” says Chuck Wilson, Denver-based chief operating officer for Nighthawk Energy Plc and formerly drilling manager of Forest Oil Corp.'s onshore US operations.

The area had been explored for gas in the early 1980s for shallower pay from the younger, Pennsylvanian-age Morrow and other formations. “During that time, natural gas prices were high,” Wilson notes. “In southeastern Colorado, probably 300 deep wells were drilled, and they were all terminated at the base of the Pennsylvanian, chasing natural gas plays.

“To our knowledge, no one tested the potential of oil in the Mississippian in that time frame. It was an unexplored area for many years. We literally searched 1,000 square miles [of well files] and there were very few Mississippian penetrations. The nearest penetrations initiated were 75 to 100 miles southeast of us on the Las Animas Arch. Other than a 3-D seismic study, we had no [well] control.

“So we decided to drill one of these wells to the Mississippian.”

The London-based E&P had gone public in 2007, planning to join in North American resource-play exploration. Soon, it won a 50% earn-in in acreage in Lincoln County with the idea, initially, of prospecting in the shallower carbonates.

“It was a unique idea,” says Mike Thom-sen, Nighthawk president and formerly chief geologist for Freeport-McMoRan Inc. “It was an area with limited production history. The production that it did have, however, was produced from Pennsylvanian carbonates and shales. We looked at it and immediately concluded that it's not your normal shale play.

“While the shale sequences are relatively thin, the quality of carbonates in between them was hard to ignore. We thought, 'There is a possibility that this could be a resource play. Let's test it.'”

An initial lease position was grown from some 50,000 acres to about 250,000 net. Wells were made in Pennsylvanian. “But our JV (joint-venture) partner at the time didn't meet with a lot of success.”

By January 2012, it was making just some

30 barrels a day. Nighthawk became operator and drilled three more Pennsylvanian wells. Then it decided to drill deeper to look at the Mississippian.

There, it found success. In November 2012, it brought on the vertical Steamboat Hansen 8-10 with an IP of 250 barrels of oil a day from Spergen as the discovery well of Arikaree Creek Field.

In May, it brought on Big Sky 4-11 with 400 barrels a day from 32 feet of gross pay northeast of Steamboat Hansen. It quickly spudded Taos 1-10 between the two, bringing it online in June with 500 a day; in July, Silverton 16-10 and Snowbird 9-15, south of the discovery well, each came on with 150.

A year later, Steamboat Hansen had made 100,000 barrels of roughly 38-degree gravity oil, which is being trucked out and is discounted some 9% off WTI. The wells cost about $1.5 million each and are not fraced.

The northern wells came on with no water and less than 50,000 cubic feet of low-Btu, 52%-nitrogen gas; the southern wells produce about 0.25 barrel of water per barrel of oil and also give puffs of gas.

Spergen in the area appears to be hydrothermally altered, Wilson says. Porosity ranges between 12% and 24%. Permeability is averaging 34 millidarcies.

“From 3-D surveys in the immediate area, there is a structural component associated with it,” Thomsen adds. “There is probably some sort of hydrothermal convection cell at work, coming up some of the high-angle structures we have in the area and laterally migrating through the Spergen.”

Given the under-pressured reservoir at 0.22 psi per foot, Nighthawk is re-entering the wells each few months for pressure testing. Wilson says, “We're looking at another series of pressure build-ups in the spring in all the wells so we can have a good model of our pressure drawdown and what is really going on in the reservoir.”

The company has 23 more wells staked on 40-acre spacing.

What little pressure the reservoir does have does not appear to be declining, he adds. “It's a very different reservoir. It has produced a lot of oil in a very short period of time and continues to do so.”

Thus, estimated ultimate recovery (EUR) has not been established for the wells yet; they haven't declined.

“These wells have produced flat. Steamboat Hansen, for example: We didn't know what we had so we brought it on at a very slow rate, trying to understand the reservoir with a very small pump in the hole. We produced it at 250 barrels a day for six months and realized we had something bigger, so we changed the pumping unit. That well is producing 400 barrels a day now.

“The offsetting wells are of the same nature. There is no decline, so we have not been able to establish what the EURs are. We are in the process of a full interpretation. We hope, by spring or summer, to be able to define what the EURs are.”

Along the arch

Other operators are exploring Spergen pay as well. About 75 miles southeast of Nighthawk's leasehold, privately held Chama Oil & Minerals LLC completed a horizontal, Pronghorn-State 16-15-48-1H, on the western edge of the Las Animas Arch in Cheyenne County in 2013. It came on with an initial rate of 485 barrels of oil and 1,662 of water per day from Spergen where it is at about 5,300 feet from a roughly 9,000-foot lateral.

Anadarko Petroleum Corp. has some 800,000 net acres in the area along the arch in Kit Carson County, primarily as a result of mineral rights it inherited when buying Burlington Resources Inc. in 2000, and it had been watching the play come to it. At press time, it was planning a horizontal Spergen test, Lincoln 1748-11-11H, along the arch in Kiowa County at about 5,500 feet, according to IHS Inc.

Will Nighthawk test its Lincoln County leasehold with horizontals?

Thomsen says, “We have asked other operators if they're going to go horizontal. They ask us if we're going to go horizontal. That is obviously the next step in this play.”

Horizontals cost about $3.5 million, though. “Nighthawk is a small company. We are funded from cash flow. To go horizontal, you're in a different price range. We believe the first group that drills a horizontal [in Lincoln County] will change the complexion of this play. My guess is that it will probably happen [this] year.

“Our vertical wells are producing so nicely we decided we are going to continue to define things vertically before we go horizontal.

“But it is something that is on everyone's minds.”

Of Nighthawk's leasehold, about 10% is held by production. “Much of the acreage has extension options of one to five years but some have no options. So there is a timeline. We have a

budget in place to maintain that 250,000 net acres.” The company is renewing leasehold, particularly around its discovery well, for between $75 and $250 an acre.

“This entire area is pretty much leased up now. If an operator wanted to take a position of 100,000 acres, they couldn't get it. They would have to buy out one of the others in the area.”

Pioneer Natural Resources Co. has some 650,000 acres, primarily in Lincoln and Kiowa counties. Chesapeake Energy Corp. has 600,000.

Meanwhile, operators are still eyeing potential in Pennsylvanian as well. Privately held, Englewood, Colorado-based Wiepking-Fullerton Energy LLC made a vertical, Aloha Mula 1, southeast of Limon, with an IP of 1,500 barrels from Cherokee. Denham Capital Management LP-backed Cascade Petroleum LLC completed Safranek 04-1296H in Marmaton for 125 barrels a day and in Cherokee for 220 barrels.

Southwestern Energy Corp., which has some 300,000 net acres under five-year term, attempted a horizontal, Ewertz Farm 1-58 1-26H, in Pennsylvanian carbonate near the arch. Encountering an oil cut of some 5%, it was shut in.

Its vertical Staner 5-58 1-8 in Arapahoe County, north of the Nighthawk leasehold and far from the arch, tested seven intervals, finding an oil cut of 40% in Marmaton. Its horizontal re-entry was completed there with 14 frac stages in July. The peak rate was 146 barrels of oil and 59,000 cubic feet of gas per day from a roughly 2,000-foot lateral. The company planned in November to further test Marmaton as well as Atoka.

To capture Pennsylvanian oil pay that sits above Spergen, Nighthawk may drill twin wells or, after the Mississippian has paid out, recomplete those uphole, Thomsen says.

“We see oil everywhere we drill. Pioneer, Anadarko, others have significant lease positions in the area now. And all with the idea of 'Let's look at this closely as a potential resource play and see what we can turn up.'”

Brown Dense

Far southeast of Colorado, Southwestern Energy may have the breakthrough in its science on the condensate-loaded Lower Smackover's over-pressured Brown Dense that straddles south-central Arkansas and north-central Louisiana. The Houston-based E&P that founded the Fayetteville-shale play in northern Arkansas in 2004 had revealed its Dense leasehold and two, initial horizontal wells in 2011 in the brittle, upper-Jurassic-age, basinal limestone that is mixed with shale and some sand.

With its eighth well, the vertical Sharp 22-22-1 1 last summer, it may have cracked the code.

“What do I tell you? We're almost ready to declare [it] commercial,” Steve Mueller, president and chief executive officer, said in an earnings call in early November. “We're getting close to knowing the key things needed to make it commercial …

“I believe we have a new discovery and our task … is to figure out how big.”

Sharp was drilled to 9,776 feet in Union Parish, Louisiana, which appears to host the greatest reservoir pressure and highest-gravity oil in Lower Smackover, which was laid down only some 150 million years ago. It came on with a peak rate of 600 barrels of 52-degreegravity oil, which is condensate, and 1.3 million cubic feet of 1,240-Btu gas a day. After 88 days online by early November, it was flowing 530 barrels and 1.1 million cubic feet on a quarter-inch choke.

The science well was fraced in three stages along the 450-foot Dense section and propped with resin-coated sand using cross-linked gel.

The well's flattening decline is promising, said Bill Way, executive vice president and chief operating officer. “We remain encouraged—I'll change that to 'excited'—about the work that's going on in [this] exploration program.”

Sharp followed five horizontal and two vertical trials, ultimately zeroing in on the center of Union Parish where Lower Smackover—the source rock for decades of Upper Smackover production—is at about 10,000 feet. Porosity ranges from 2% to 8%; permeability, from less than 0.1 to more than 1 millidarcy.

Its first attempt—the 3,700-foot-lateral Roberson 18-19 1-15H in Columbia County, Arkansas, where Dense is at some 9,200 feet and bottomhole pressure is 2,750 psi—came on in December 2011 for 103 barrels of 38-degree-gravity oil and 180,000 cubic feet of gas. It cost more than $12 million and remained shut in at press time.

Moving south into Claiborne Parish, its second horizontal, Garrett 7-23-5H 1, was also given a 3,700-foot lateral, but where the rock is at 10,700 feet. Costing more than $12 million as well, it came on with 301 barrels of 50-degree-gravity oil and 1.7 million cubic feet of gas in 2012. Bottomhole pressure was 4,100 psi. It was shut in to assess reservoir pressure and whether to run pipeline to it.

Then, moving farther south, Southwestern went into Union Parish with its third horizontal, BML 31-22-1 H, completing it for a peak rate of 421 barrels of 52-degree oil and 3.9 million cubic feet of 1,220-Btu gas from a 19-fracstage, 4,500-foot lateral where the rock is at 10,400 feet and pressured at 5,700 psi. In its first 30 days, the well averaged 353 barrels and 3.3 million cubic feet a day.

Mueller told securities analysts at the time that the pressure BML encountered was “completely unexpected ... There have been over 30 wells drilled previous to us [in or through] Brown Dense. They hadn't seen the high pressure. None of those wells [had] seen the high pressure …

“It caught us off guard in our … thought process out there.”

The company changed up its science project then, completing a vertical, Johnson 21-22-1 1, two miles north to test more of the 450-footthick formation than a horizontal could test. Using linear gel in the frac, it screened out.

About six miles east of BML, the vertical Dean 31-22-1E 1 was soon completed with three frac stages, perforating a total of 12 feet of the rock, using white sand and slickwater. It came on with a peak rate of 214 barrels and 1.3 million cubic feet on a 10/64-inch choke. Bottomhole pressure was 6,500 psi. After 70 days online, it was making 150 barrels and 1 million cubic feet a day from a 12/64-inch choke; bottomhole pressure had become 3,000 psi.

Going back to the BML well, it spudded the horizontal Doles 30-22-1H 1 two miles away, sending a 5,700-foot lateral toward the BML, putting 22 frac stages on it and spending more than $12 million, including for some 55 drill days. It peaked with 435 barrels of 53-degreegravity oil and 2.5 million cubic feet from bottomhole pressure of 5,400 psi on a 26/64-inch choke. After 95 days online, it was producing 160 barrels and 2.2 million a day at new pressure of 4,250 psi.

By August 2013, after some 290 days online, BML was making 104 barrels and 1.2 million a day; the vertical Dean, online for 155 days, was making 82 barrels and 509,000.

Southwestern reported, “The company remains encouraged by the flattening production profiles of both … wells.”

At press time, it had two more Union Parish verticals under way as well as a vertical trial northwest of there in Columbia County, where it had made its first Dense attempt with the horizontal Roberson.

Way said in the November call, “(We will) apply what we're learning from these vertical wells to see if we can unlock more contactable reservoir volume with horizontal wells in the future. We continue to test not only different completion techniques but also different theories in each of these wells.

“While I realize the results we are reporting to you are only on a few wells with short production histories, we're excited about the potential in the Brown Dense.”

Southwestern holds 475,000 net acres in the play at an average cost of $419 an acre with net revenue interest averaging 81%. Most of the leases have four-year terms with options to extend another four years.

Pre-dating Southwestern's work in Dense was EOG Resources Inc., which attempted the horizontal Endsley 1-24H without success in 2009 in Lafayette County, Arkansas, in the northwestern corner of the Dense window. Southwestern bought the leasehold but has let it expire.

Cabot Oil & Gas Corp. tried a horizontal, Denny 1-32H, in 2011 in Union County, Arkansas. It tested 206 barrels a day and was temporarily abandoned when its permit to flare expired. New Orleans-based Ankor E&P Holdings Inc., a business of the Korean National Oil Corp. and Samsung Oil & Gas USA Corp., acquired the position.

Southwestern's Dense condensate production is priced at a $5 to $10 premium to WTI. There are four refineries within the area with about 135,000 barrels of daily refining capacity, combined.

Mueller believes a $12-million Dense well is profitable if making 425 barrels and 4.2 million cubic feet a day at a market price of $80 oil and $3 gas. Into sales for a year, BML looked like “we will get our money back,” Mueller said.

The second vertical, Dean, “won't make much greater return but it will make a little bit of rate of return. And then you've got this [Sharp] well that we just drilled ... It had some issues that we had on the drilling side and we also [did] a lot of science [on it] but, at $10 million, this well still is above our ... economic hurdle.”

One of the new verticals, Hollis 27-22-3 1, it has spud in Union Parish might cost less than $7 million to drill and complete “and we think we can get that down to $6 million … [for] high, high, 80%- [to] 90%-rate-of-return-type numbers.”

To date, the three best wells are verticals, he added. The company plans to continue to make verticals to accelerate its schooling in the rock's mechanics for less cost than horizontals.

He estimates the high-pressured Dense area may cover some 150,000-plus acres but the super-high pressure might not be essential. “You always want higher pressure, but we just don't know enough about the whole area yet to know what works and doesn't work.”