Many of the Permian Basin’s earliest and most legendary oil discoveries were made in the Central Basin Plat¬form in the 1920s into the 1940s, primarily in the shallow Guadalupian-period dolomitic San Andres. Beginning in 1926, with the Yates Field discovery at the southernmost end of the CBP, and through 2012, the platform had produced more than 13 billion barrels of oil, or 45% of all basin production, according to a Howard Weil (now Scotia Howard Weil) report in 2012.

The platform’s Wasson Field, in northern Gaines and southern Yoakum counties, was discovered in 1937 and remained on the EIA’s list of top 100 U.S. oil fields in 2015 at No. 8 in terms of proved reserves. Goldsmith (1935) was at No. 18; Slaughter (1937) at 25; Lev¬elland (1945) at 38; Seminole (1936) at 42; Fuhrman-Mascho (1930) at 46; North Ward Estes (1927) at 47; Yates (1926) at 72; and Fullerton (1942) at 89. Of 26 Texas oil fields on the EIA list, nine are in the CBP.

The platform’s resources were traditionally produced from vertical wells, tapping the con¬ventional-porosity and -permeability carbon¬ates as well as the underlying conventional Leonardian-period Clearfork and Wichita-Albany groups.

Today the CBP’s pay is surfaced primarily via waterflooding. But during the past decade, Apache Corp. began to test a variant of lifting the oil from just vertical wellbores. With great success, it began to capture more of the oil in place from horizontal wellbores.

It and at least two privately held E&Ps have taken the process a step further, by landing hor¬izontal wells on the flanks of these high-perm, high-porosity fields where San Andres, Wichi¬ta-Albany and other pay had been elusive.

Logs and land

Rick Lester and fellow Opal Resources LLC team members had been drilling vertical wells in the Midland Basin since 2008, but by 2013, rising leas¬ing costs had made the program too expensive. “We were looking for a different basin that could be prospective and that wouldn’t break the bank,” Lester, Opal’s CEO, said.

The group came upon some 10,000 acres in the CBP that looked interesting for Wich¬ita-Albany pay. “The attraction is that these are much shallower wells than in the Mid¬land Basin. At about 7,000 feet—and less for shallower zones—it’s much less expensive to fully develop.”

Goldman Sachs-backed Opal, along with its area-of-mutual-interest partners, now has some 32,000 net and more than 50,000 gross acres. The leasehold is on the northern part of the plat¬form near Fullerton Field as well as south, near Dollarhide Field. “It’s a fairly large position,” Lester said. “Some of it is blocky; some of it is not.”

Putting that position together wasn’t easy. A great deal of the CBP is held by production from legacy fields and another good-sized portion by majors and large independents. Some names have changed since 2012, but the Howard Weil report cited the Top 4 operators of active wells in the CBP as Occidental Petroleum Corp., Apache, ExxonMobil Corp. and Chevron Corp.

Among them, they held more than 17,000 active CBP wells. All 14 operators on a short list of companies holding more than 500 active wells each were publicly held, except for Cita¬tion Oil & Gas Corp. Their active-well count combined was just shy of 30,000.

Lester said, “So you have a barrier of entry to overcome, and there is this belief that what has been drilled up there is all you’re going to find. The platform had a reputation of being a sleepy place with a lot of stuff held by stripper wells and that it would never be redeveloped.”

While all of those old wells made for hur¬dles in leasing, they and the failures outside of the fields were extremely valuable in studying where laterals of up to a mile might be landed. “We analyzed every well we could get our hands on,” Lester said. “The more we looked at it, the better we liked it.”

The vertical control is particularly helpful in avoiding water-prone areas as well as in finding porosity streaks. “A lot of the wells were fail¬ures. It’s a very mixed bag across the platform, especially along the northern portion.”

That’s where Apache’s experience inspired.

The Opal team surmised that “all they’re [Apache] really doing is connecting existing porosity zones across the lateral. You have a lot of variations in porosity in the rock, so vertical development is hit or miss. You might drill a vertical well in one area and make a good well and move over a quarter-mile and have nothing.”

Drilling through all the good and not-so-good areas of the rock averages out the poros¬ity, Lester said, which ranges between 6% and 20% in the Wichita-Albany. Permeability var¬ies between one and 10 millidarcies. “Shale is in the nanodarcies. We’re in conventional rock, but it is still tight. We’re not in huge per¬meability, but it is in the millidarcies.”

Faulting is an issue, so Opal has licensed 3-D seismic. “Water encroachment is prob¬ably the bigger issue,” Lester said. “We use careful petrophysical analysis to avoid con¬tacting the wet zones during completion oper¬ations. You also have the potential for wet Clearfork zones that have to be managed.”

Vertical-well logs have shown a clear water-transition zone. “If staying out of that zone, we feel pretty good we won’t encounter that issue,” Lester said. “We will have some water, but not enough to make a well uneco¬nomic.”

It’s less apparent where the water is in the Clearfork. “I don’t think the Clearfork is a viable candidate for horizontal development. You don’t really know where you’re going to run into those water zones.”

In addition to Wichita-Albany, Opal brought in a partner last year to target the San Andres, which overlies the Clearfork. The partnership has a third San Andres well. Separately, Opal was completing its first Wichita-Albany well in August. “They manage the shallow and we manage the deep,” Lester said.

To date, the laterals are one section long. “This goes back to what was overlooked about it: It’s largely broken up by a lot of mineral owners. It’s not an easy leasing play. Getting sections to drill a two-mile lateral is tough.”

Oil take-away infrastructure isn’t a con¬cern in the 90-year-old CBP; takeaway for the associated gas is. “The pipe is in the area, but no one seems to want the gas. The [mid¬stream operators] we talk to want to charge an arm and a leg in hook-up fees. It’s a different environment from what we’ve seen in the Mid¬land Basin.

“It has been a bit of a surprise. We’re not including much value at all to the associated gas nor gas liquids. The pipes are there, though.”

It’s unclear whether horizontal development of the CBP could rank with that of the Midland and Delaware basins. “Those have so many zones that will support horizontal develop¬ment,” Lester said. But, in terms of individual well economics, the Opal group expects the CBP will be comparable, he added.

“The question is going to be, ‘What is the extent of the development,’ and that is yet to be determined. I think the [horizontal] San Andres is getting pretty well proven across the platform, but the Wichita-Albany is a ways behind that.”

Making barrels

Terry Dobkins, president and CEO of Elk Meadows Resources LLC, agrees. “The plat¬form can be complex. It definitely is not a widespread or blanket horizontal play.”

Like the Opal group, Elk Meadows was looking in 2013 for a prospect that would be economic, of course, but also risk-appropriate for a private equity-backed E&P.

The CBP came up through Elk Meadows’ land department’s contacts. “After screening the prospect, we felt it looked promising,” Dobkins said. “We started studying what other operators were doing in Andrews and Gaines counties. They were getting encouraging results. It wasn’t home-run stuff yet. But it looked good enough for them to continue.”

The team’s analysis was a geosciences proj¬ect to understand the water and oil saturations, porosity, structure and formation continuity.

Also like Opal, TPH Partners LP-backed Elk Meadows is targeting the edges of the old, giant fields.

“When you step off the structure, you either go into water or low permeability that isn’t economic to drill with vertical wells,” Dobkins said. “What we needed to do was study the San Andres off the structures and look for low per¬meability, but good oil in place.

“When you have that combination, it becomes a horizontal well candidate. We might have old vertical wells around us that were very uneconomic because of the low permea¬bility. But it makes an ideal place for us to drill horizontally.”

The land issue can be daunting, he con¬curred. “At times, the rock looks good, but there was just no way to get the land; other times, there wasn’t the oil in place we need.”

Also, these wells need to steer clear of waterflood fields. Permeability and porosity are higher there, but there can be a lot of water too and depleted oil in place.

Rights can be split up. “Often, we might get just the San Andres and above or rights down to the Lower Clearfork. Often, the lessors keep the Wolfcamp and depths below that. The Wolfcamp has such a big name that it drives the cost way up.”

Where Wolfcamp does appear in Elk Meadows’ study area in the northern CBP, it is mostly non¬prospective. “There are some exceptions, but we don’t view the Wolfcamp as a target in this area we’re developing.”

The Denver-based E&P has put together 16 contiguous sections with 7,000 net acres for a pro¬spective-well inventory of approximately 96 one- and 1.5-mile laterals, all in Andrews and Gaines counties. It has six horizontals online in the San Andres to date and was planning to move in a rig in early September to drill two more.

The company completed JD Biles 2-1H and 9-1H and the Goen 22-2H in the first half of 2015. June production was some 1,100 barrels of oil equivalent per day (boe/d), 99% oil. Biles 2-1H, which had been online more than 500 days as of May, had made more than 70,000 barrels of oil. Biles 9-1H, online about 350 days, had also made more than 70,000 barrels.

After Dobkins presented at Hart Energy’s DUG Permian conference in May, Seaport Global Securities LLC analysts reported that “The company’s type curve showcases solid economics, driven by high oil cuts and low well costs—[for] 35% internal rates of return at strip prices—from 238,000 boe EUR wells, 96% oil, costing $2.2 million [each]. Initial results look encouraging as well: Oil volumes on Elk Mead¬ows’ first three completions are tracking some 25% above the company’s type curve through 300 days of production.”

ENERGEN, RING

Energen Corp. holds 122,000 gross and 88,000 net acres in the CBP. Jim McMa¬nus, chairman, president and CEO, said in an earnings call this past spring that the company is looking at horizontal potential in the position. But the asset isn’t core to the Permian pure-play E&P, while its Midland and Delaware holdings are, he added.

The company’s position includes Andrews County’s Fuhrman-Mascho Field, which it pur¬chased from Range Resources Corp. for $182 million in 2009. Seaport Global Securities LLC analysts reported in June that Energen “would prefer to fund a large acquisition—in the Mid¬land or Delaware—via the sale of its Central Basin Platform asset, which it believes could garner more than $600 million, as opposed to using equity.”

Ring Energy Inc. co-founder Tim Rochford worked the Furhman-Masco with verticals at his E&P, Arena Resources Inc., which was sold in 2010 for $1.6 billion to SandRidge Energy Inc. Rochford went on to co-found Midland-based, publicly held Ring, which has about 31,000 gross and 18,000 net acres in the CBP in Gaines and Andrews counties about 10 miles north of what was Arena’s portfolio.

The small-cap raised a net $61 million this past spring with the sale of 11.5 million shares, paying off its bank debt. In August, it began drilling its first of three horizontals in the platform.

John White, senior research analyst for Roth Capital Partners LLC, wrote that, if the initial three horizontals work as well as Ring estimates, “the horizontal San Andres could be a real game-changer” for the company. “Consider the possibility of three wells, with IPs ranging between 400 and 600 boe per day,” White wrote, “and compare that against Ring’s average production during [the second quarter of] 2016 of 2,138 boe per day.”

Ring estimates completed well costs will be between $2 million and $2.8 million.

Jason Wangler, a senior vice president and equity analyst for Wunderlich Securities Inc., wrote of Ring’s potential, “The horizontal program has started, and it could go on for miles.” He expected results this month from the first three horizontals. Ring’s leasehold may allow for 20 to 30 horizontals, he added.

Irene Haas, a managing director and senior analyst for Wunderlich Securities Inc., reported at press time that San Andres verticals histori¬cally had an F&D cost of between $12 and $15 per boe. While more expensive, fracked horizon¬tals of one to 1.5 miles have an F&D cost of some $7 per boe, when considering their larger EURs. “While early stage, the ability to spend eight to 10 times the cost of a vertical well, but receive some 15 times the reserves is quite com¬pelling and more data should be coming in [this half],” she wrote.

Water disposal is into the Devonian at about 8,000 feet, Dobkins told Investor in August. It can be disposed of in the lower portion of the 1,500-foot-thick San Andres, “but that’s not the first choice,” Dobkins said. “I’d rather not put water there, unless it is off the field and I know it’s not a place where we mean to produce oil.”

The going so far has been slow, given the need for mapping and the difficult land situa¬tion. Then, “once you have the land and begin drilling, you have to keep a careful eye on costs, especially the handling of produced water and electric-power infrastructure,” Dobkins said.

“All of us need to be careful right now at this oil price. It’s a slower pace than we might like, but I think it’s prudent for now. However, the econom¬ics are still excellent, and we intend to continue to expand our position in the play.”

Editor's note: In the October print issue, an E&P executive who worked for Arena Resources Inc. was cited in the "Central Basin Platform" article as the co-founder of Ring Energy Inc. Instead, Tim Rochford is the co-founder of Ring and was the founder of Arena. We regret the error.

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