If you need to be on site for a West Texas oilpatch job at dawn, be sure to allow extra time to get through the traffic lights in Midland, because the boom is back and traffic is stacked. After nearly a century of conventional drilling in the Permian Basin, unconventional drilling and completion technology has arrived. Horizontal is supplanting vertical basinwide. The only conundrum: which of the multiple pay-zone intervals present throughout the basin to attack first?

“You can’t help but be excited by the Permian Basin,” said John Christmann, executive vice president and chief operating officer of North America for Apache Corp. “It’s been around for almost 100 years and is getting better as we go. It’s chock-full of zones that 20 years ago you never would have thought would be economic today. And now we’re bringing on wells at rates we never dreamed of.”

Specifically to the Midland Basin, where the Wolfcamp and Spraberry dominate, horizontal rigs have increased from 4% of total rigs running in early 2011 to 38% in early 2014, ac- cording to the Baker Hughes rig count. The shift is on in full force.

Pioneer Natural Resources Co., the largest operator in the basin, has the most prolific results among horizontal operators. Pioneer CEO Scott Sheffield explains the allure of horizontal: “A vertical well comes in at 100 barrels a day with maybe a 30% return. But now, for four times the cost, we’re drilling horizontal wells that come on at 3,000 barrels a day. A vertical well will produce 140,000 barrels of oil equivalent over 30 years; now we’re producing that in one horizontal zone in four months.”

And unlike most other unconventional basins, the Midland Basin stacks up a dozen potential oil-bearing formations in a 5,000-foot column of organic shale zones that for the past 40 years were thought to be uneconomic. Said Sheffield, “That’s 12 Bakkens or Eagle Fords.”

Horizontal rig count in the Midland Basin has increased 35% since early 2011.

Serendipity goes deep

At dawn on a crisp March morning, H&P Rig 232 drills the Crossbar Ranch #3025H for RSP Permian Inc., one of three rigs working the Crossbar Ranch lease just northwest of Midland. It is looking for the Wolfcamp B, one of four “benches” present in the thick Wolfcamp formation. A Wolfcamp D well has already been drilled on the same pad, and RSP expects the Middle and Lower Spraberry zones will eventually see a drill bit from this pad, though not immediately.

“That’s the serendipity of the play,” says Bill Huck, RSP Permian vice president of operations. “We’ve got up to six identified horizons in different areas. We’ll be developing this with stacked laterals” in different pay zones. “We’ve got plenty of these to do this year.”

Midland-based RSP Permian is an amalgamation of Mike Grimm’s Rising Star Energy LLC and Steven Gray’s Pecos Production Co. (thus the “RSP”), which came together in 2010 to jointly make a $300-million purchase with vertical Wolfberry in mind. It has 40,000 net acres situated west and north of Midland balancing the Midland and Martin county lines. However, the horizontal Wolfcamp play that rose like a haboob from the south changed the mission.

“We closely watched as the play developed to the south, and as it came north, the results seemed to get better,” said Gray, CEO, director and co-founder of RSP. “We were skeptical— we weren’t sure the economics were any better than our vertical wells. Our vertical wells were good wells.”

RSP drilled a Wolfcamp D well (referred to by some operators as Cline) to test the concept, but encountered mechanical problems, with positive shows. It then tested a Wolfcamp B well in fall 2012, the farthest north that had been drilled to date, and “that was a very successful well, about 800 barrels per day [bbl/d]. So we started drilling the Wolfcamp B.”

Not yet sold on the returns, Gray set out to prove or disprove the economics of horizontal vs. vertical wells. It didn’t take long.

"As we drilled a few wells, the returns on horizontal wells were better than on the vertical wells," he explained. "Just the amount of oil you recover from horizontal wells is a magnitude greater than you're ever going to recover drilling vertical wells. They're at a higher expense, but they come on at big rates and pay out quicker."

With interest piqued, RSP’s technical staff evaluated well logs up and down hole and identified what it believes might be treasure. “We kept looking at the Spraberry Formation think- ing, ‘This looks just as good as the Wolfcamp, and nobody’s testing it.'”

In 2013, RSP tested two Spraberry horizontal wells, shallower and with less subsurface pressure than the deeper Wolfcamp, and liked the results. "Early results look just as good as the Wolfcamp," Gray said, noting average results of 600 to 800 bbl/d IP rates and lower costs to drill. "We think the Spraberry has as much potential in our part of the basin as does the Wolfcamp. I don't think many people appreciate that."

Today the company targets four zones— Wolfcamp B and D, and Middle and Lower Spraberry. “We’ve had successful wells in all four zones,” although the Wolfcamp D is lower priority because it exhibits “some complexities” and higher costs due to its depth. The Wolfcamp A looms hopeful but remains untested.

Yet the expense of shifting to a horizontal drilling program was a monumental task to the then-Natural Gas Partners-backed private company. Rather than $2 billion of capital to develop the position vertically, Gray estimated RSP would need $10 billion to drill it up horizontally. “The private-equity model didn’t work for that kind of money,” he said.

Selling out of the position didn’t work either, as Gray doubted the company would receive value for the vast unproven reserves. The only way to unlock the value was to drill it, and the only way to pay for that was to go public. RSP Permian went public in January with “the right zip code in West Texas,” according to Raymond James analyst John Freeman, and has 80% of its $350-million budget directed to horizontal wells this year.

The company has drilled 40 operated horizontal wells to date, with another 30 nonoperated in a joint-venture development with Diamondback Energy Inc. It plans to run four horizontal rigs and two vertical rigs in 2014, with more than 1,000 horizontal locations identified on 160-acre spacing. It expects to average more than 10,000 boe/d, more than a 40% year-over- year jump.

“It’s an exciting time to be developing reserves here in this basin,” said Huck. “The horizontal takes it to the next level. It’s going to be more lucrative than the vertical.”

The Midland Basin is rich with a layer cake of more than a dozen potential oil-bearing targets.

Goldilock rocks

By 2011, Dallas’ Pioneer Natural Resources was a Wolfberry vertical-well manufacturing machine. Forty-four rigs punched almost 700 vertical wells into the West Texas rock that year, and 40-acre spacing yielded to 20. Vertical production topped 53,000 bbl/d and was climbing.

Then two horizontal test wells drilled in Upton County in October of that year, at the southern portion of the company’s vast acreage holdings, set the stage for change. Giddings 2041H and Giddings 2073H, drilled to Wolf- camp B with 5,300-foot laterals, IPed at 750 and 800 boe/d, respectively, and 800 days later exhibit average EURs of 725,000 boe.

A massive shift that would transform the company had begun.

“It’s all about the economics,” Pioneer’s Sheffield said. “The best way to develop this, we’ve concluded, is horizontal.”

As the largest leaseholder in the Midland Basin, Pioneer controls an 825,000-acre swath up the axis of the basin, a legacy position built on major oil company castoffs since the 1980s. Horizontal testing began in the southern region, which was not conducive to Wolfberry verticals, and where leases were set to roll off. Over the past two years, more than 100 horizontal wells have de-risked the Wolfcamp A, B, C and D intervals here.

In early 2013, Pioneer partnered 60-40 with Chinese national oil company Sinochem in the company’s southern Midland Basin area, on some 200,000 acres in Upton, Reagan and Irion counties, for Wolfcamp and deeper intervals. In 2014, the duo plans 115 horizontal wells with an average lateral length of 9,400 feet. It will test downspacing from 116-acre spacing to 77 acres per well, and could go to 50. Eight rigs will be concentrated in northern Upton and Reagan counties, considered higher-return areas.

Beyond the joint-venture line, Pioneer added a rig in 2013 and began a progressive northward march into the heart of the basin, where on some 600,000 acres it holds essentially 100% interest. Here, it has proved up four of its six target zones—Wolfcamp A, B and D, and the Lower Spraberry. Middle
Spraberry and Jo Mill formations remain.

“We have models that show this asset can take us to over 1 million barrels of oil a day in the next 13 to 15 years,” Sheffield said. “How many companies can say that about one asset?”

Nine wells within Pioneer’s northern program—essentially Midland, Martin, Glasscock and Andrews counties—have averaged 24-hour IPs of 1,850 boe/d, and 1,150 boe/d after 30 days. Internal rates of return, on drilling and completion costs of $8 million, average from 45% to north of 100% across the four zones.
Newer wells with extended laterals should be higher, he said.

“I see a good range in the Wolfcamp B being from 2,500 to 3,000 barrels a day on a 24-hour test. That’s not juiced; that’s natural flowback of the well.”

Pioneer shows Wolfcamp B EURs of 800,000 to 1 million barrels, based on historical 7,000-foot-lateral wells. However, it is transferring learning from its southern program and moving to 9,000-foot laterals here as well. The E.T. O’Daniel 1H well in Midland County, drilled with a 9,200-foot lateral, debuted at 3,500 boe/d and produced 100,000 boe in its first 70 days. It pays out at 120,000. The extended lateral well cost 20% more, but gained 40% in EUR.

“It is going to do 1.4 million barrels,” Sheffield said. “It’s extraordinary.”

Chris Cheatwood, Pioneer executive vice president of business development and geosciences, said the rocks are superior to the Bakken or Eagle Ford shales. “I call them the Goldilocks rocks: everything is just right out here."

Pioneer escalated its northern region program from five to 16 rigs in early 2014. Two-thirds of its horizontal program is aimed at the Wolf- camp B currently, with the Wolfcamp A and D garnering the remaining rig time on three-well pads. Recent tests into the Lower Spraberry could result in a modification shortly to four- well pads. “These four zones are by far the drivers of our inventory and asset base,” said Sheffield.

And the Lower Spraberry could rise in prior- ity, he believes. “It can compete with the Wolf- camp A and D because it’s got the most oil in place. It’s our fourth zone now but could move to No. 2.”

Unlike the Wolfcamp zones, which peak in the first week, Spraberry wells take about four months to peak. Every Spraberry well—shallower and under less pressure, and producing volumes of water—gets put on submersible pump right away.

“You don’t get the initial high rates, but the wells don’t decline much either,” he said. And costing $1.5 million less than Wolfcamp wells, “we think they will compete economically.”

Pioneer recently sold its acreage in Dawson and Gaines counties, citing less thermal maturity at this far northern fringe of the basin compared with the rest of its block. “There will be [wells] that make EURs of 400,000 to 500,000 barrels” in those counties, Cheatwood said, “but we’ve got 20,000 locations that will be 800,000 to 1 million.”

Pioneer’s Permian capex for 2014 totals $2.3 billion, or 80% of its whole. Already, it has escalated to 24 horizontal rigs, up from five last year, with plans to reach 50 within five years.

“At 50 rigs, that’s 40 years of inventory” on current spacing, Sheffield observed. “And we’re only at 24 rigs now.” Vertical rigs are now down to 11 going to zero over the next five years, acting only to meet continuous drilling obligations.

To develop its Permian resource potential, Sheffield estimates it will take $200 billion in capital. To kick-start the program, last year Pioneer raised $3 billion from Sinochem and an equity offering, with plans to sell its Alaska and Barnett assets to stoke the pot.

“That allowed us to get the rigs going,” he said, “but what’s nice is you have wells that pay out in a year and a half. It’s almost self- funding. We don’t need additional sources of capital.” The program will be self-funded by 2016, he projected.

The Wolfcamp shales including the Cline Formation, are the primary targest of most horizontal operators today, but the Spraberry shale zones above them are gaining attention as well.

Concentrated development

Apache Corp. has long been a conventional producer of tertiary oil on the Central Basin Platform, but the Houston-based E&P established its footprint for unconventional exploration in the Permian Basin through two transforming deals in 2010. First, it acquired Mariner Energy, a shallow-water Gulf of Mex- ico player with some 200,000 gross acres, including an onshore Midland Basin position, then BP Plc’s 1.7 million gross acres in the Permian Basin as the British giant looked to raise cash following the Macondo oil spill.

Apache, based in Houston and with operations in the U.S., Egypt, Australia, North Sea and Canada, established a Midland office and quickly staffed up to 345 employees to evaluate the grab bag of resource opportunity. Four years later it has a firm grasp on the task at hand, and is now planning to spend almost 31% of its total 2014 E&P budget in the Permian region, more than any other. Overall, Apache boasts 3.3 million gross acres Permian-wide (1.7 million acres net) and is the most active driller with 40-plus rigs in motion, 24 of which are drilling horizontal.

“We’ve got a tremendous amount of zone here that we’re working,” said John Christ- mann. “It’s a very large basin with tremendous opportunities.”

In the Midland Basin, Apache claims some 635,000 net acres along a nearly 200-mile-long axis from Lynn and Garza counties in the north to Schleicher and Sutton counties in the south, holding estimated resource potential of 3 Bboe in a host of hydrocarbon-bearing zones. It views 400,000 net acres as prospective for Wolfcamp shale zones with resource potential of 846,000 boe net, and has six horizontal rigs operating in its Barnhart Field in central Irion County in the southern basin, to mass-produce Wolfcamp zones.

“Counter to others, we have not been drilling one well per section,” Christmann said. “We’ve focused our activity in one area, because we believe in execution and unlocking the keys to how we’re going to develop this resource base. Not many people have parked rigs in an area and learned what we’ve learned.”

Barnhart pad drilling began in earnest in 2012, with 109 horizontal wells drilled as of the company’s February 2014 analyst day. Here, Apache targets the Upper, Middle and Lower Wolfcamp zones (or Wolfcamp A, B and C, as referenced by others), although it has not been specific about whether any one bench receives more attention than others. Twenty-four-hour IPs on featured wells (em- ploying gas lift over sub-pumps) have exceeded 1,000 boe/d on laterals 7,500 feet or longer; 30- day IPs have exceeded 700 boe/d. Oil comprises 55% of the flow. Production in Barnhart rocketed from zero to 18,200 boe/d in just 24 months.

“Our resource potential in the Wolfcamp has increased by 500 million barrels since our June 2012 analyst day,” he said. “In the Midland Basin, we’ve tripled production in three years.” Apache’s Wolfcamp type curve in Barnhart shows 600,000 boe EUR per well, and “that’s conservative,” said Christmann. In the past six months, the company has tested a new completion design, and wells have responded with a “step change in productivity,” he said.

“We’ve made some breakthroughs that are going to yield results. We don’t want to slide up our type curves at this point, but we’re out- performing the data that we’ve put out. We’re very encouraged.”

After updating for improvements, Apache shows a 41% rate of return on $6.3-million wells, which were trimmed from $7.7 million, an 18% cost haircut. The company plans 131 horizontal wells in the Wolfcamp alone in 2014.

Though the Wolfcamp garners more rigs at present, the Cline Shale was in fact Apache’s first Midland Basin horizontal target. When it acquired Mariner, it was on short notice to save expiring leases in Deadwood Field in Glasscock County, and mobilized a fleet of rigs to get the job done. Since 2010, Apache has drilled more than 50 wells targeting the Cline. It estimates 665 MMboe net total resource po- tential across the Cline on 510,000 prospective net acres.

“Where we’re active, we’re having good success,” Christmann said. Apache’s Cline map stretches across several counties north to south, but “right now, we’re spending our money in Glasscock County,” he said.

Like in the Wolfcamp, drilling is concentrated in a single area—Deadwood Field—to drive efficiencies. Two type curves are modeled here: one for a mile-long lateral well, with an EUR of 424,000 boe; another for a mile-and-a-half lateral estimating 526,000 boe EUR. Longer wells are drilled when lease lines allow. “It was important to us to know we could make economics on the mile-longs or the mile-and-a- halves,” he said.

Early Cline wells from 2012 experienced conflict between zones, but after reworking completion techniques, EURs increased dramatically. “We were able to increase those by almost 30%” for “optimized” laterals, he said. Recent 24-hour IPs range from 460 boe/d to more than 900 boe/d, averaged on wells with laterals just longer than 4,000 feet. A test well in Reagan County farther south with 760 boe/d IP gives hope the play will prove economic there as well.

Deeper than the Wolfcamp, Cline wells cost $8.5 million for the longer laterals, with a published rate of return of 23%. Three rigs will tap the Cline in 2014 with 35 wells planned.

Apache is taking what it has learned in these two focal areas to test all four zones in Reagan, Upton and Midland counties, where it holds 232,000 net acres. With 23 Wolfcamp wells already drilled, seven rigs will drill an additional 53 planned horizontals in 2014. “We’re marching west and north on our asset base,” he said. “We’re delineating and moving to pad development.”

Apache’s early-phase concentrated development plan is driven by reducing costs while maximizing recovery potential. “We like to develop all the benches at once before moving on. You want to try to use the energy in the reservoir as efficiently as you can early on,” Christmann said.

Of note, Apache is not abandoning its vertical program; rather, it plans 170 this year targeting Spraberry through Fusselman pay zones. “We’ve got great numbers on the verticals; they compete as well with or better than the horizontals,” he said. Singling out the recent Squire 9007 well in Glasscock County, he noted the 800,000 barrel EUR. “That’s a bigger EUR than some of the horizontals. The wells we’re drilling now have even better economics than the horizontals. We’re drilling a lot of vertical wells with blow-away numbers.”

Today, Apache is making more than 60,000 boe/d in the Midland Basin, tripling its production over three years. It will spend about $1.3 billion in 2014 and plans a balance of both ver- tical and horizontal wells in its program.

The Midland Basin “is a world-class oil play,” said Christmann. “We’ve got a really deep inventory here.”

Perfect rock

“We were always a horizontal player,” affirmed Randy Foutch, chief executive of Tulsa- headquartered Laredo Petroleum Inc. “We never went at this thinking it was a vertical play.”

Laredo, which was formed in 2006 and went public in 2011, holds some 143,000 net acres largely in Glasscock and Reagan counties on the eastern side of the Midland Basin. The company drilled its first horizontal well in 2008, and believes it is the first to go sideways in the Cline and other Permian formations.

“We have four proven zones: Upper, Middle and Lower Wolfcamp, and the Cline. We think we’re looking at a resource potential of 1.6 billion barrels just on that, and it’s growing. We’re not even close to done. In our view, this is a reset of the Permian Basin,” said Foutch.

But Laredo does have more than 800 vertical wells, with five rigs adding more down through the deeper Strawn formation. Many of these were added via its acquisition of Broad Oak Energy three years ago, and are still being drilled to meet continuous drilling obligations and to gather data needed to optimize horizontal drilling. Broad Oak, he emphasized, al- though a vertical player, was bought specifically for its horizontal optionality.

Foutch has been drilling vertically in the Permian for 20 years, but his heart—and wallet— is now with the horizontal plays.

"We enjoy an opportunity set of 3,000 to 4,000 vertical wells on our acreage that has a rate of return that during most of my career I would have been very pleased to have. That’s pure develop- ment we can drill cheap. But we’re trying to minimize how many vertical wells we drill at Laredo because the horizontal wells have such better economics. On average, the rates of return on the horizontals are twice or better.”

As a comparison: Assuming $90 oil and $3.75 gas, vertical wells return 20%, while horizontal targets in the Cline return 30%, Lower Wolfcamp 40%, Middle Wolfcamp 45%, and Upper Wolfcamp 60%.

And Foutch particularly likes Laredo’s position, which is situated over the thickest deposition of the Wolfcamp and Cline formations. “It’s 2,000 feet of almost perfect rock for a re- source play with a lot of oil in place.”

With two-thirds of its Cline position considered derisked, and half of its Wolfcamp zones, Laredo already tallies more than 40 years of horizontal drilling on its proven portfolio at its current rig cadence. In 2014, it has moved to developmental pad drilling in these areas.

“We think a pad will have multiple laterals with at least four wells to the north and an offset pad with four to the south,” each a set of four targeting a different zone. Should other zones prove commercial, Laredo is setting up the pads to accommodate future drilling. Yet while drilling a slate of wells from a single pad at once boosts cost efficiencies, logistics such as shutting-in production to accommodate offsetting completion activities and infrastructure will likely result in two to four wells being drilled at a time in the near term.

After nearly 100 horizontal wells currently producing, that plan is based on 120-acre spacing (660 feet apart) per zone, with four 7,500- foot laterals stacked vertically.

Foutch discounts 24-hour IPs due to the high-decline nature of the wells, and prefers to compare rates and accumulations beyond six months. Still, the company re- ports average 30-day rates of between 675 boe for the Cline on a two-stream basis, up to 800 boe for Lower Wolfcamp. Those numbers would be 20% higher except natural gas liquids, which remain in the gas stream, are not booked in its production or reserves.

“If we’re showing 800 barrels a day for a 30-day average IP for the Lower Wolfcamp for long laterals, that’s effectively 1,000 barrels a day. Some people miss that fact. We’re com- fortable our numbers compare favorably to any- one out there.”

Laredo budgets $1 billion for 2014 to run seven horizontal rigs. At present, said Foutch, all four of its proven zones compete equally for capital, but he did acknowledge the Middle Wolf- camp has seen more drillbits of late over others.

“Our best wells recently have been Middle and Cline. Six Middle Wolfcamp development wells are exceeding type curves of 650,000 boe. And the Cline is very economic.”

Best of all, “We’re not opportunity constrained. Our focus this year is to move from the exploration phase into the development phase.”

Million-barrel payback

When flying in to Midland, take a look out your window. If you see a rig or three near the northern or western perimeter of the airport, chances are those are deployed by Diamondback Energy. A recent nearby well, the Spanish Trail South 501H, was drilled in October, with an extended 8,926-foot lateral drilled in the Wolfcamp B formation. It IPed 1,033 boe/d flowing. To date, it has recovered more than 100,000 boe and is still producing almost 600 boe/d.

“Expectations are we’ll recover about 1 mil- lion barrels equivalent out of that well,” said Mike Hollis, Diamondback vice president of drilling. “At a cost of $9 million, that’s more than 100% return.”

Hollis, a former Chesapeake Energy and Burlington Resources veteran, has extensive experience with horizontal drilling in multiple Lower 48 shale plays.

Diamondback, headquartered in Midland, with a $3.4-billion market cap, is popular among Wall Street investors as a Permian pure- play producer. It was formed as Windsor Permian in late 2007, led by CEO Travis Stice, and took its current name at IPO in 2012. Initially, Diamondback was a vertical Wolfberry operator, and shifted aggressively to horizontal drilling soon after the influx of public funds. That move, made ahead of its peers, who were still drilling vertical wells, garnered production growth of 150% in 2013, forecast for more than 110% this year.

The core focus area of its 70,000-plus net acres is west of the city of Midland in Midland County, where three of its five horizontal rigs are active in the Wolfcamp B zone. Most wells average 7,500-foot laterals, a balance between lease geometry limiting lateral lengths, and potential technical challenges at the longer ends. Average 30-day IPs are 650 boe/d, and Diamondback projects two-stream EURs in its core area at 638,000 boe. The company gets an uplift from owning the minerals here as well.

It has drilled approximately 25 horizontal wells in Midland County and approximately 60 horizontals in the region to date. Diamond- back drills on two to three-well pads, the num- ber mitigated somewhat by the quantity of water needed for simultaneous multi-well completions.

The vast majority of near-term wells will continue to target Wolfcamp B, but “the Lower and Middle Spraberry look very prospective,” he said, referring to nonoperated results from recent RSP Permian-operated Spraberry wells. “Midland is fantastic as to the number of zones capable of producing.” Offset operators are also testing Cline and Atoka.

Diamondback launched its horizontal program on a small block of acreage in southern Upton County, using “close-ology” to operators kicking off horizontal Wolfcamp delineation in Irion County to the east. There it has drilled approximately 20 wells, with currently a single rig working.

Important Upton data points: Wolfcamp B EURs in the eastern acreage are projected at 604,000 boe on a two-stream analysis for about a 50% return. An operated Lower Spraberry test that is waiting on completion may define the next target here as well as offset operator activity in the Wolfcamp A and C.

The trend, however, is northward, and Diamondback has blocked up acreage in Andrews, Martin and Dawson counties, where one rig is “bouncing around” delineating the Wolfcamp B opportunity. At press time, one well in Andrews was in the process of completion; two are flowing back in Martin; and a well in Dawson County is flowing back.

“Once we get that data, you may see us move more rigs farther north,” Hollis said.

Diamondback expects 2014 capex to approach $475 million, to include up to 75 horizontal wells. While its drillbits are concentrated in Wolfcamp B, the company does not discount upside horizontal targets such as Spraberry, Wolfcamp A and C, even Atoka and Clearfork, where it projects total resource potential across seven zones of 393 MMboe. It’s just that the Wolfcamp B is that good.

“It’s hard to take the drillbit out of a proven, high-rate-of-return play,” he said. “We’re going to stay heavy in our de-risked play, and move into other plays as they become de-risked over time. But the economics are very strong in every one of these benches that we’ve tested.”

Tall City's order

After exiting a previous private-equity-backed Wolfberry vertical player in 2011, Mike Oestmann and his new partner noticed the horizontal Wolfcamp play “getting obvious.” In 2012, he joined forces with a former Exxon colleague to tackle the horizontal Wolfcamp in the Midland Basin. He and Joe Magoto, a long-time Ryder Scott reservoir engineer and most recently with investment bank Parkman Whaling, came together to form Tall City Exploration LLC in May 2012. Denham Capital backed the new team with an initial $200-million equity commitment, along with funding from Jim Henry of Henry Petroleum and other local investors.

Relying on advanced petro-physical shale analyses of more than 300 logs, the team scoped the entire Midland Basin. Seeking niches where land might be available, the company bought into a 50% nonoperated position on 10,000 net acres with Element Resources in northern Howard County, then continued consolidating acreage until it blocked up 75,000 net acres at the northeastern corner of the play. Tall City also accumulated an additional 17,000 acres in Reagan and Crockett counties in the heart of the horizontal Wolfcamp play, bringing holdings to approximately 92,000 acres.

“We looked at the rocks in the whole Wolf- berry section; that was our skill set,” Oestmann said. “And we thought the Wolfcamp A has the best-looking rocks of all the sediments out there. We thought it had the potential to generate the most oil.”

Tall City, based in Midland with an office in Houston, proceeded to drill six wells alongside Element, with four on production, and “all four are doing well,” said Magoto. “We’re getting IPs between 600 to 800 barrels of oil per day”; or 900 boe/d for three streams. And the decline rate is slower than for wells in more southern counties, thus making more oil over time. “Howard is looking strong,” he said.

“The rocks tend to be more brittle in the north than they are in the south. They fracture better and tend to stay open better.”

He projects Wolfcamp A recoveries near 540,000 barrels for oil only, 750,000 on an equivalent basis, generating returns in the 40% to 50%-plus range.

“If those are half-a-million-barrel wells, we’re looking at almost 300 million barrels” of recoverable resource in a single Wolfcamp A bench. While fewer zones are present here than in the center of the basin, Wolfcamp B and Lower Spraberry promise upside that could add another 200 million barrels.

“We’re not saying Howard County is the epicenter of the play,” emphasized Magoto, “We’ve just pushed the northern edge of commerciality.”

Although northern Reagan County looked good on the logs, industry activity there made blocking up large sections of acreage difficult. Even so, Tall City assembled 10,000 net acres in Reagan and has subsequently drilled four wells. All are still in the process of completion, but offset industry results give confidence the acreage is substantially de-risked.

“We’re very pleased with our logs and initial flowback results down there,” Magoto said. He expects three to four zones to eventually be developed.

Personal history aside, Tall City is focused horizontally, Oestmann said. “Economics are better to drill this horizontally. Ultimately, it will generate higher returns. We are just scratching the surface of the potential of these horizontal plays; we’re in the infancy of horizontal drilling.”

Currently, Tall City has two operated rigs running, one in northern Howard County, the other in Reagan. The company has interests in 11 total horizontal wells to date. “We plan to keep two rigs running all year, plus our half with Element. We’ll drill about 25 wells this year and 25 next year.”

Tall City’s budget is $200 million for 2014, made possible by an additional $100 million committed by Denham and $100 million lined up in mezzanine financing.

We’re excited about the initial results, and now it’s a matter of execution. We’ve done a lot of science to de-risk the wells, but there’s nothing like drilling a hole and seeing what it produces.”

True to form, Oestmann looks to exit before developing the full 571-well potential of the Wolfcamp A at 160-acre spacing. He thinks 50 to 60 wells over the next year and a half should do it.

Almost a century ago on acreage deemed vir- tually worthless, the wildcat Santa Rita No. 1 in Reagan County—named by its New York backers for the patron saint of the impossible— blew its top in 1923, verifying the discovery that began the Permian Basin conventional oil play. Since, the Permian has produced 29 billion barrels of oil through conventional means, according to the Texas Railroad Commission. Now, with horizontal drilling and hydraulic fracture technology, the clock is reset to explore the basin all over again.

Tall City recently leased land offsetting the original Santa Rita discovery well west of Big Lake, and plans to drill a horizontal Wolfcamp well there this summer.

“It’s intriguing that we’re talking about an emerging play in a basin that’s nearly 100 years old,” said Magoto. “We’re very confident in our results down there, and we intend to push the envelope.”

Prospectors like Tall City and others chasing the horizontal bounty in the Midland Basin are opening up a new oil rush. Pioneer’s Sheffield said, “This play is going to be the largest oil field in North America—it’s already up to 75 billion barrels of oil recoverable, and is going to be more than 2.5 million barrels a day. Not even Alaska’s North Slope got over 2.5 million barrels a day.

“What the Marcellus is to the U.S. for natural gas,” Sheffield said, “the Spraberry/Wolfcamp is to oil.”