Good Old-Fashioned Oil And Gas

San Antonio-based private E&P company RLU Oil & Gas Inc. drilled two shallow oil wells in Medina County, South Texas, in November and plans about the same number each month ongoing. That’s down from six or so per month prior to the turn in oil prices, but at $140,000 per well, costs are half of what other regional operators are achieving today. That’s because RLU has been diligent—and creative—in cutting costs, primarily by running its own drilling and service operations.

When most public and private equity-backed companies changed course to chase unconventionally drilled and completed shale plays, the majority of bread-and-butter private operators like RLU stayed the course: drilling low-cost, conservative conventional plays in the Lower 48.

“By doing our own service work, we can knock 40 cents off the dollar [rather] than having it hired out,” said Will Carter, president and owner of RLU. “It gives us a lot of control. We can still be economic at $30 oil; we can still be in the black.”

RLU concentrates on vertically drilled targets above 2,000 feet in Medina and Bexar counties, currently concentrating on the Anacacho Lime at 1,400 feet at its deepest. These wells pay out in 19 months, garnering a 2-to-1 return in the current climate.

“At $90 oil, payouts were off the chart,” said Carter, “but these are 50-year wells, they are long-life wells. You can’t lose sight of that. You can’t just think six months out.”

Will Carter, president and owner, RLU Oil & Gas

“Everybody’s gone to shale, and totally ignored these opportunities,” said Ed Hirs, a managing partner for Hillhouse Resources LLC, a start-up focused on the Texas Gulf Coast. “When the RRC data show a 76% hit rate on 362 Frio wells drilled post-3-D seismic, all you need is for one of these to pay for about eight shale wells.

“Things that work at $20 per barrel and $1 per Mcf, that’s where we want to be. That’s the economics at work down here.”

The story is the same in conventional basins across the U.S. Free from the high costs and fast declines of shale wells, these low-cost, long-lived conventional wells are garnering new favor in a weaker commodity price environment. Here are a few of their stories.

The truck-mounted, 330-horsepower Failing 1500 rig stands not much higher than the grove of wild mesquite trees that surrounds it, glowing in the predawn. It spudded only the evening before, the doghouse abutting an oak tree that the landowner wanted to save. Where it sits on a map, it looks like the rig could be drilling an Eagle Ford Shale well, but in reality it’s just a little too far north. Instead, the Felisa Valdez #2 is targeting Anacacho at 900 feet total vertical depth, and will take no more than a day and a half to finish drilling.

The well is in Chicon Lake Field, which was discovered in 1929, targeting primarily the Escondido Formation. Many of these wells drilled in the 1950s at 350 feet depth are still producing, accounting for more than 1 million barrels of oil over the decades. The field is on the uplift of a shelf, just miles from the Texas Hill Country and metamorphic, non-hydrocarbon-bearing rock. The shallowness is exacerbated by the well sitting on top of a volcanic serpentine plug, similar to a salt dome.

“I don’t know if the Anacacho is going to work here,” said Carter, “but I know the Lit and San Miguel will work here. We’ll probably complete two of these zones.”

RLU has 4,500 acres leased in the area, with about 100 core wells to drill, but the formations change from fault block to fault block, he said. “We’re still trying to figure out all the formations, especially the Anacacho. Cross a fault block and you’re in a whole new world.” Yet he doesn’t use any seismic help to identify the faults, because “it’s cheaper to find it out with a log and a drillbit.”

Although this well is exploring prospectivity in the Anacacho, Carter doesn’t consider it the target zone of the program.

“Our primary target is whatever makes us money. We’ve been punching holes and testing over about a seven-mile range, and what we have found is that, in one area, one zone will work good, then when you march to the west or the east, that zone isn’t so shiny. But the beauty of the geology out here is that you have everything being squeezed down to within 2,000 feet. We can see eight different oil pays that have a potential to be productive.”

Carter formed RLU in 1981, a defensive move when he bought the assets of a bankrupt operator that had made the family farm non-farmable. He plugged wells, reworked others, and buried flowlines that had crisscrossed former farmland. A rancher by experience and education, Carter got his petroleum landman degree and worked for the predecessor of EOG Resources. In the early 1990s, he hooked up with a geologist to sell prospects with a carry, and by the early 2000s, he began holding onto a third working interest in everything, his niche in deep South Texas. RLU grew from there.

RLU operates 29 wells in Starr, Zapata and Jim Hogg counties, producing from the Queen City and Reklaw formations, but the advent of the Eagle Ford scuttled his drilling program along the Mexico border region. Rigs became too expensive, and too scarce. “Want a 1,000-horsepower rig? Forget it. They were charging $100,000 to drag a rig down there.”

So he returned to the region around the family farm west of San Antonio, as it reminded him of a mini-Permian Basin with multiple stacked pays.

“It’s all about return on investment—that’s what we’re all chasing regardless of commodity price.” He tries to run one base at a time, he said. “We’re not home run hitters. We’re trying to chase wells where you can get a 2-to-1 return, with a 50% internal rate of return and under a two-year payout. We’re happy with that, and on that shallow stuff we’re doing west of San Antonio, we’re getting that.”

Initial production rates average 15 and 20 bbl/d. “If we can get 17,000 barrels of target reserves, then we’re in great shape.” Although he won’t commingle zones now, he foresees further reserves behind pipe.

Much of Medina and Bexar counties were unleased when Carter returned to his stomping ground, as many of the farmers who rely on gravity and pivot irrigation systems had either experienced negative consequences from bad operators in years past who made irrigation impossible on the land, such as his own, or didn’t want to risk it. Carter, a landowner and farmer himself, understood how to address their concerns and earn their trust.

RLU minimizes its impact by using temporary wooden mat pallets for its pads, rather than caliche, softening the footprint. It drills on a closed fluids system, removing the need for earthen pits. It works its roads and pads around the edges of fields, and buries pipelines out of the way of irrigation systems. It only reworks wells when there are no crops in the field.

“At the end of the day, we’ll have a pumping well pad that is literally 10 feet by 20 feet—that’s it. They can go back in and irrigate and farm it.”

Before the oil price crash, RLU drilled six wells a month. Now, “we’re not drilling as much,” said Carter, “but we’re still drilling, and watching every dollar to make sure we’re in the black at the end of the day.” He plans to remain active and “stay in first gear and moving forward” until the oil price turns around.

“I think we’re looking at a year. If we get back to $55 oil, we’re in great shape. With this commodity, that’s not hard to achieve in short order, ’cause that’s the nature of the business.”

Carter makes an analogy of the current situation to a wagon train on the Oregon Trail.

“We’ve already shucked Mama’s piano and silver, but guess what? The oxen are still pulling the wagon. We’re leaving stuff on the trail, but we’re gonna make it to Oregon.”

Robert Tucker hails from San Antonio, but after starting out as a landman for Hunt Oil Co. in the ’60s, he formed West Bay Exploration Co. in 1981 and chased Shell Oil and the Pinnacle Reefs up into the Michigan Basin. He’s been there ever since.

“They were just good enough to make you want to move up there and try to find some,” he said about the prospects. Turns out, there was enough to keep him active all these years. “Most people don’t know there’s oil in Michigan, so we’re trying to keep that a secret.”

The Traverse City, Michigan, explorer is now the biggest producer in the state, with 4,000 bbl/d, yet is in an era of transition. The Trenton-Black River trend it has been developing vertically over the past six years in the southern third of the basin in Jackson and Calhoun counties is reaching maturity.

Robert Tucker, CEO, West Bay Exploration

“We developed Napoleon Field in southern Michigan, about 50 wells in the Trenton-Black River and a number in the Albion-Scipio trend. We’ve looked it over pretty good, and there aren’t a lot of drilling opportunities left.”

Now, Tucker holds high hope for Trenton-Black River in the upper two-thirds of Michigan.

“Very few wells have been drilled in the upper area of the state actually looking for Trenton-Black River,” he said. “It’s been kind of ignored in the northern part of the state, and I think there’s a lot of opportunity for it up there.”

West Bay shoots its own seismic, and the company is diligently identifying targets to direct its leasing program somewhere within the 50 northern counties prospective for Trenton-Black River, likely in the central basin.

“We go in with technology first to determine where we want to lease, and we’re in the process of doing that now. We have very few development wells left to drill” in the southern basin. “We’re pretty much now back to wildcatting.”

The Trenton-Black River in this part of the state sits at about 7,000 to 8,000 feet. Tucker likes the prospectivity of the Traverse Lime and Dundee formations as well. The company is presently running no rigs, and only drilled a handful of wells in 2015.

“We’re doing our homework during this period. We’re developing a bunch of projects that we’ll drill when we get some improvements in prices, but we’re circling the wagons a bit, I guess you’d say. We’re just trying to hold on.”

Tucker said the southern Michigan development wells paid out in a year, with a nine out of 10 hit rate, but wildcats hit one in 10, which isn’t palatable to him in the current environment.

“We may drill a few wells at these low prices,” he said, with a couple planned early in the year, “but we aren’t going to do any big programs at these prices. We’re in a holding pattern. We’re not in a position where we can spend a whole lot of money doing anything until the price of oil comes up a bit.”

In the meantime, “we’re stockpiling prospects.”

Matagorda County along the Texas Gulf Coast was the most drilled county in the U.S. prior to the advent of the Bakken Shale. However, one Texas ranch in particular remained largely untapped, even though it offered a dozen conventional plays and possibly a source rock shale. After successfully exiting their unconventional prospect in the Niobrara, the former D-J Resources partners John Harms, Erin Goerges and Hirs reformed as Hillhouse Resources, and turned their sights on leasing the ranch—with success.

Before he died, legendary oilman and the grandfather of shale George Mitchell, upon hearing that the Hillhouse team had leased the large tract in Matagorda, told managing partner Goerges, “My God, you got the whole ranch? This is amazing!”

Based on some notes from the 1950s that Hillhouse partner and geologist Harms had stored in his garage, the team left Colorado and came to Matagorda “on the off chance of finding cheap, shallow gas drilling. We found more after we started peeling back the onion. Decades ago, they could not drill water wells without hitting gas at some point,” Hirs said.

RLU Oil & Gas is drilling shallow, vertical wells of less than 2,000 feet in Medina County, Texas. “We’re still trying to figure out the formations,” said president and owner Will Carter.

The ranch currently has no production and Hillhouse has yet to drill, but Hirs is quick to highlight surrounding successes. He points to a nearby salt dome well at 3,800 feet that has produced 80,000 barrels in 10 years, costing just about $200,000.

Petrodome Energy has invested about $15 million into two wells on 400 offsetting acres with some $100 million in revenue, he said. “That’s a tremendously successful investment for Petrodome with very flat decline curves.”

Devon Energy’s Silverspoon well, drilled around 2005 just across the lease line, has produced more than 16 billion cubic feet (Bcf) and 161,000 barrels of oil. “The numbers are incredible. While they’re not cheap and a little risky, the risk/reward is better than a shale well of similar cost.”

Even on the ranch, an old shallow Exxon unit formed by Rex Tillerson and shut in during Hurricane Rita had produced more than 4 Bcf.

Conventional wells typically—at least on the Gulf Coast—can reach payout in less than two years and produce for 30 years, he said. “Some of the shale wells drilled across our acreage in the Niobrara have already been plugged and abandoned. Some of those wells did not reach payout.”

Hillhouse’s conventional geophysicist, Andy Mirkin, used the seismic data to identify eight “really nice, deep, geologically separate targets” in the Upper and Lower Frio. These deep vertical targets below 11,000 feet are Hillhouse’s treasure trove, costing in the neighborhood of $7 million to drill and complete with more downhole risk than shallower targets. But the reward justifies the risk, which is mitigated by the historical success across the region with 3-D seismic.

The shallow Miocene traces across the western swath of the ranch, a gassy formation that produces oil and gas liquids as well. “Those are normal pressured, very simple wells to drill, and they produce for a very, very, very long time,” said Hirs. They should cost a mere $250,000 to $500,000.

And they’ll get drilled sooner rather than later. “Now that costs are down,” said Hirs, “it’s a great time to drill these wells.”

Hillhouse has identified upward of 38 to 50 drilling locations in the Miocene and Upper and Lower Frio formations.

In the middle of it all is the Anahuac—a shale, though not an identified, producing shale.

“John really does believe this might be a great shale play; there is production from vertical wells in the shale nearby. If it becomes a big play, then we have achieved a bonus.” The rush to shales, however, has created a vacuum in funding: Investors have been sold on the aura of the repeatable returns with relatively lower risk at high oil prices. “Many of the funding sources only invested in shale wells,” he said.

The downturn over the past year has caused a hiccup as well. The project is currently self-funded, but Hirs said they would prefer to bring in additional private investors and partner with operational teams that have independent wealth but are sitting on the sidelines currently. Said Goerges, “I see no reason to reinvent the wheel. There are very talented, amazing teams who can work this area. People are seeing this as a lot less risky than a year ago.” For 2016? “I’d love to see our first four wells online. I think people have forgotten that you can drill conventionally. I’m looking forward to watching this grow and bloom.”

Bill Daugherty’s been on both sides of the fence in his career—conventional and unconventional—and after selling out of 35,000 acres of Utica Shale, his Lexington, Kentucky-headquartered company, BlackRidge Resource Partners LLC, has set up shop in two conventional plays in southern Illinois and eastern Kentucky. It’s here where the lines between what’s conventional or unconventional get blurred.

After selling his 26-year-old company NGAS Resources Inc. to Magnum Hunter Resources in 2011, Daugherty partnered with another ex-NGAS executive, Bill Barr, to form BlackRidge. Both have experience in the Illinois Basin, and have now assembled approximately 15,000 acres in Illinois, with interests in the Mississippian Lime and Silurian Reefs.

“We were more interested in oil in the Illinois Basin than we were in natural gas in the southern Appalachia Basin,” he said. “Over the years, we’d both seen opportunities that had been passed over in the Mississippian Lime in Illinois, so we started looking.”

To date, the basin has given up more than 4 billion barrels of oil, he said, a prime target of the majors before they were lured away to the Gulf of Mexico decades ago. Even NGAS had concentrated here in the late 1980s. This past year, BlackRidge drilled five vertical Mississippian Lime and three vertical Silurian Reef wells, targeting the St. Louis, Salem and Warsaw formations in the Lime and the Geneva Dolomite in Silurian Reef structures at about 4,000 feet depth.

“There are several stacked pays. We’re trying to develop prospects with multiple zones available so we can commingle production.”

These wells are completed conventionally with acid or nitrogen-assisted acid jobs, he said. And they are economic today, he emphasized. At 100,000 barrels EUR and a well cost of $600,000, give or take, “it’s economic.”

Daugherty’s aim is to hit 60% to 70% of its wells, assisted by seismic. Dry hole costs are $300,000, but a Mississippian well will IP at 50 to 125 bbl/d, and a Silurian Reef well near 100.

“We’re looking at a three-year payout on average, and these wells are long-term producers. We can expect these to economically produce as long as 30 years or more.”

In the southern Appalachia Basin, in Lawrence County, Kentucky, the company is targeting the conventional Berea sandstone down to 2,000-foot depths—with unconventional technology. The well-known vertical play has been extensively drilled over the decades, but “technology has stepped up the play substantually,” he said.

BlackRidge participated in eight horizontal wells last year with laterals averaging 3,500 feet. “If you’re in the right spot, you can get reserves of 60,000 barrels or more, at costs of about $1 million per well. And there’s a pretty strong gas component.”

The wells come on strong near 100 barrels daily under current completion techniques. They taper quickly, about 60% to 70% in the first year before settling, but “a good portion of the well is paid off in the first year.”

Daugherty anticipates operating next year, and extending laterals to 4,500 feet, thus increasing EURs to 100,000 barrels. BlackRidge holds 5,000 acres of leases and options in the play. While the company has had a few working interest partners that have slowed, most of the prospects have been funded as BlackRidge has developed them.

“We have slowed our activities down a bit and have extended some time periods for developing prospects on the table,” he said. “We would drill more wells next year if oil was higher, but now we’re focusing a lot more work on identifying the better prospects before we drill.” But BlackRidge is not drilling to hold any leases. “If it doesn’t make economic sense, we’re not doing it.”

In 2016, Daugherty said, BlackRidge will likely drill up to 26 wells: 10 in the Berea sandstone, 10 Mississippi Lime, and six Silurians, one of which will be a horizontal test. Additionally, the company is acquiring acreage in the Rogersville Shale play in Kentucky.

The downturn produces disadvantages in securing financing, developing marginal projects and securing services that might have folded up shop, but it also provides opportunities given less competition and more lease availability.

“We can assemble a lease position that has potential three or four years out,” he said. “You just have to make sure you have current prospects that make sense in this economic market.” Ultimately, in his mind, conventional for BlackRidge is better than unconventional today. “Most of my experience is in shallow, unconventional shale wells and, you know, the payouts were acceptable when gas was at $5 per Mcf, but it takes too long to get your return at $3 gas. That’s the reason we moved to conventional oil plays—you miss on a few wells, but you have some real winners, and those winners pay for the dry holes.”

A field geologist in Alaska for the U.S. Geological Survey in the mid-1970s and, subsequently, an exploration geologist for Texas Oil & Gas, Michael Morris struck out on his own in the early 1980s and has been drilling prospects ever since. And although his shingle for Cypress Production hangs in Azle, Texas, west of Fort Worth near the heart of the Barnett Shale, he’s been working conventional plays on the Gulf Coast in Texas and Louisiana from the beginning.

“Our model has been to develop and drill our prospects with industry partners and then operate the well once it’s producing.” said Morris. “In general, we try to keep at least a quarter of the prospects we develop and drill.”

Cypress has drilled some 50 onshore wells over the past 10 years and operates 20 across Cameron, St. Landry, Vermilion, St. Martin and Iberia parishes. He employs several consulting geoscientists to analyze data from the company’s extensive 3-D seismic data inventory to generate prospects. Cypress then acquires the prospective acreage and presents the idea to its partners.

“The cream of the crop prospects are definitely the ones getting sold right now,” he said, “and Cypress has had some success getting them sold. We’ve been fortunate to have the right prospects for this market.”

Even in the challenging market presented in 2015, Cypress pushed forward and drilled two wells in Cameron Parish; one a dry hole, the other a producer with 68 feet of oil and gas pay. “We believe that well will make several times our money over the next five years,” he said. Cypress plans to offset that well with two others on trend.

In 2016, he has three more planned with total AFEs of $6 million. Two are funded, but a 13,000-foot test in Cameron Parish is still lacking 40% of funds. “That’s been the challenge, because it’s deeper and more expensive.”

Cypress and its partners currently place a higher emphasis on oil prospects while many target both oil and natural gas. Morris said, “The old timers always told me, ‘A good prospect always sells,’ and I’ve continually found that to be true.” He evaluates prospects from a risk-reward point of view: how good is the data; how good is the sand quality; and is it in a structurally good position to produce the reserves?

“Every depth has a different cost of drilling, so deeper wells have to have quite a bit more reserves. We’re looking for prospects where we can make five times our money in a 10-year period.”

In reaction to the current pricing climate, Cypress too has teamed up with a reservoir engineering firm to buy producing minerals and royalties, which he said show average annualized returns of 13% to 23%. “It’s a perfect time to be buying minerals and royalties,” he said. Even in the current environment, Morris plans to push forward drilling wells. “Geologists are optimists by profession,” he said. “We think we can find economic reserves in any environment. You just have to work toward assembling the best prospects, because it’s a difficult time to raise money.”

Also in the Illinois Basin, Viola Oil & Gas LLC sees an opportunity to bring modern technology to a host of legacy pay zones up and down a vertical wellbore. Viola president Sean Fitzgerald sees the basin as a parallel to the Permian Basin.

“The Illinois Basin has been drilled for more than 100 years,” said Fitzgerald. “It has multiple stacked pay with both sand and carbonates, but no one has brought hydraulic fracturing technology to this space before in a big way. We think we can put together a sizeable position and be able to drill vertical wells—not horizontal wells—and be able to develop these resources using modern hydraulic fracturing techniques.”

The Houston-based, private company was formed in early 2014 with $60 million in backing from Talara Capital Management. Fitzgerald, along with partner Michael Rozenfeld, had worked together at Shell Oil and then Rosetta Resources before setting out on their own. Their third partner, Kris Johnson, was a college classmate with significant experience in this basin and the Midcontinent region at large.

The target is Mississippian zones from the Valmeyeran period, including the Warsaw, Salem, St. Louis and Ste. Genevieve formations at or around 4,000-foot depth, though specific locations were not disclosed. The well-drilled Chesterian sand sits above those and is a target as well. The company aims to amass a meaningful position.

Where traditional operators might have targeted one zone with six to eight feet of perforation, Viola will identify multiple targets via logs “and target three or four as opposed to just one, then frack it. We’ll do 10 times the size of perforations, and commingle it all.” The modern completion techniques being employed “are dramatically different than what people were using 20 or 30 years ago.” Well costs are $500,000 to $600,000, with 13 put online through 2015. Even though some wells have been online for over a year, Fitzgerald held results and economics close to the vest. “The results in 2014 were encouraging enough to motivate us to continue drilling in 2015, even with the drop in prices. Certainly, the wells are economic at $50 oil. The Illinois Basin is an old, oil-producing area that keeps bearing new fruit. Additionally, we see similar opportunities to apply this technology in other areas of the country.”