A version of this story appears in the August 2017, edition of Oil and Gas Investor. Subscribe to the magazine here.

If you’re in the horizontal San Andres action on the Permian Basin’s Central Basin Platform (CBP), then you’re playing on the edge by filling in the gaps between major legacy oil fields and tapping into the transitional zones (TZ) and residual oil zones (ROZ) below and between these fields.

“I would describe this as one of the best-kept secrets in the oil field,” said Lance Taylor, founder, president and CEO of Steward Energy II LLC. “I know people have heard about it, and the common perception is that it is a bit of a niche play. It may not be as glamorous as the Midland or Delaware basins, but I challenge anyone to compare economics against this play’s breakeven oil price under $20 per barrel. If oil prices continue to decline, we will be drilling long after the deeper basins slow down.”

With all the attention being focused on the Midland and Delaware basins, it might come as a surprise to find out that the CBP is the major source of oil in the Permian Basin. About 30 billion barrels of oil (Bbbl) have been produced from the Permian and 55% of that oil has come from the San Andres carbonaceous dolomite—a conventional formation—on the CBP and Northwest Shelf. Only about 10% of the Permian total has come from oil shales.

“When people say the Permian Basin, I think it is predominated by the Delaware and Midland basins. A lot of people lose sight of the fact that the San Andres was the first reservoir of the Permian Basin,” said Matt Gentry, president and CEO of Dallas-based Monadnock Resources LLC.

Five of the top 10 highest-producing Permian Basin oil fields are on the CBP—Wasson, over 2 Bbbl; Yates, over 1.4 Bbbl; Slaughter, over 1.3 Bbbl; Levelland, over 700 million bbl (MMbbl); and Seminole, about 700 MMbbl (as of March 2013). These are vertical wells in legacy fields that are producing from the main pay zones.

Yates Field was discovered in 1926 and is the southernmost of the large oil fields on the eastern rim of the CBP. Seminole Field was discovered in 1936, followed by Wasson and Slaughter fields in 1937. Levelland Field began production in 1945.

The horizontal San Andres play began to pick up speed around 2009. It’s currently driven primarily by private companies with private equity funding. The leaseholdings of these firms look like patchwork quilts between the major fields.

Horizontal drilling and long laterals are driving this latest San Andres play. “Just applying these technologies to a conventional rock makes it attractive. It is interesting that we developed such amazing technologies and techniques and then applied them to some of the worst rocks in shale plays,” laughed Taylor.

Economics boost horizontal play

“The entry cost is very, very attractive. Companies are competing over $40,000 or $50,000 per-acre positions in the basins to the east and west. You can still get leases here for hundreds of dollars per acre or acquire someone else’s acreage for low-thousands of dollars,” Taylor said.

The primary areas of interest in the CBP and Northwest Shelf run through Andrews, Gaines, Yoakum and Cochran counties in Texas and into Lea, Chavez and Roosevelt counties in New Mexico.

John White, senior research analyst at Roth Capital Partners LLC, agreed. “The attraction of the play is the economics. You have drastically lower completion well costs. What we are modeling will be a less steep decline curve of the production in the early years. We also feel some comfort with the fact that the San Andres is a conventional reservoir. It is a dolomite, not a shale.”

As a conventional reservoir, it has naturally occurring porosity and permeability, which requires less intense hydraulic fracturing than is required in the Wolfcamp and Spraberry shales, he added.

More publicly traded companies will joined the play, as evidenced by Yuma Energy Inc.’s play, as evidenced by Yuma Energy forged a joint development agreement covering 33,280 acres in an area of mutual interest and acquired an 87.5% working interest in about 2,269 acres (1,985 net acres) in Yoakum County to horizontally develop the San Andres play.

The San Andres is a shallow formation at a depth of 4,000 to 5,000 feet with legacy fields producing from the main pay zones. The operators drilled into these zones to just above the water level in the San Andres. The flanks of the main pay zones were not delineated, leaving oil in the TZ beyond the boundaries and below the legacy fields. The ROZ is the upper section of the San Andres that is not under a main pay zone.

“We’re applying this new technology to these historic fields and coming off the flanks of the fields with compelling economics to do so,” Gentry emphasized.

“Costs for a 1-mile lateral are changing right now because of the cost structure going up,” said Terry Dobkins, president and CEO of Denver-based Elk Meadows Resources LLC. “A year ago, we were at $2.3 million to $2.4 million for a 1-mile lateral. Now, we’re probably looking at $2.8 million to $2.9 million. A lot of those costs are going up on the completion side. We have to watch that closely.”

Water production and scale are major issues for the San Andres. “You’re going to make a lot of water in this play. Without cheap disposal, this play really wouldn’t work,” Gentry said.

Most operators drill their own saltwater disposal (SWD) wells into the Devonian and have their own gathering systems. Monadnock is able to dispose of its water for about 10 cents per barrel. “Most operators would say they are in the 10-cent to 25-cent range,” Gentry continued.

Depending on a variety of factors, oil cuts initially range from 5% to 40%. “Once the well pumps down and you get the well into a steady-state flow condition, we see on average our oil cuts level out around 10% to 15%,” explained Josh Bryant, vice president of engineering and project development for Flower Mound, Texas-based Pacesetter Energy LLC.

Initial production rates have been as high as 1,000 bbl/d with production averaging 300 to 600 bbl/d. Producers are using electrical submersible pumps to move well fluids.

Can the horizontal San Andres play make money? Some of the numbers that Midland, Texas-based Ring Energy Inc. has been sharing show that the company’s return on investment (ROI) for a 1-mile lateral with a net oil price of $45 is about 2.5 to 1 on a discounted ROI with an internal rate of return (IRR) of 103%. On the 1.5-mile lateral at $45, the ROI is about 3.4 to 1, and the IRR is around 190% net, according to Danny Wilson, executive vice president of operations of Ring Energy.

Working together for success

One of the more surprising aspects of the horizontal San Andres play is how closely the private companies work together and share information.

“Each group tries something different, and the results are shared. All of the players active in Andrews and Yoakum counties have done a great job being willing to share a degree that I don’t think has really been done before in the industry.

“The openness of all the producers in this play, I think, has really helped everyone move up the learning curve a lot faster than maybe any of us could have done by ourselves,” Bryant said.

“We all share ideas with one another and are generous with our data. We want to make sure we help each other succeed. It is unlike anything I’ve experienced in my career,” Taylor said.

Dobkins concurred, “I think all of us out there as operators are sharing information and trying to learn from each other on the best way to complete these wells. I think we’ll see increases in our economics and reserves as a result of this cooperation, and I think this is unusual. It tends to be small companies that are working this play

The companies are working together on questions such as: Are longer laterals better? There are also questions about the staging of laterals, how many clusters, how many perforation shots, what kind of frack fluids, how much proppant and how much frack fluid.

“It really comes back to again being open and honest with yourself about what your completion is really doing, communicating with your operating partners across the fence and all of us learning together,” Gentry added.

From vertical to horizontal

Since the early 2000s, Pacesetter Energy LLC has been active in the San Andres. “At that time, we had several thousand acres in Andrews County that we acquired with an eye on vertical well development. The program was successful until the 2008-2009 oil price crash. At that point, we began to see the technology progress toward horizontal drilling and recognized the value it could create in the San Andres. So we decided that was the direction we wanted to go as a company,” Bryant said.

As early entrants into the Barnett Shale, the original principals in Pacesetter had experience with horizontal drilling even before they transitioned into the CBP. “They understood the additional value horizontals could bring to a traditionally vertical well play and knew that same thinking would apply in conventional rock,” he continued.

Beginning in 2009, Pacesetter began pursuing leasehold acquisitions and delving into the technical specifics of various wellbore designs, completion techniques, frack designs and modeling what kind of results should be expected.

“We spent the first-year fine-tuning our cost assumptions and production forecasts before drilling our first horizontal well in Andrews County in 2010. Since then, we’ve drilled 15 horizontal producers in the area,” he emphasized. “We currently operate 11 horizontal wells and have participated on a working-interest basis in about 50 horizontal wells.”

Pacesetter is also the only company to drill a 2-mile lateral in Andrews County. The well was drilled with a 10,000-foot lateral and completed with 44 stages utilizing a single cluster per stage design.

The company continues to be active in northcentral Andrews County with about 6,000 net acres. Two wells, including the 2-mile well, were drilled in November 2016. Each of the wells had an IP rate of over 1,000 bbl/d and 30-day IPs of over 800 bbl/d. For the first five months one well had a cumulative total of about 120,000 bbl and the other around 80,000 bbl.

Pacesetter is trying to target what it considers to be the main pay portion of the San Andres Formation. “One of the active discussions among the San Andres horizontal players is to define the characteristics of main pay production, ROZ production, etc. From what we’ve seen, the ROZ conversation is probably a little more applicable on the northern portion of the CBP (Gaines, Yoakum and Cochran counties). In Andrews County, we believe we are primarily producing from the main pay and TZ,” Bryant said.

Over the last four to five years, the company has put lot of work to understand the correlation of geology data (structure, well logs, mud logs, etc.) to the production data. “We’re just trying to build a full picture of what all of this data is telling us. We’re definitely blessed with some good geology, but we also believe that area-specific drilling and completion techniques play a part in that as well,” he explained.

The company has also utilized chemical tracers to understand the productivity of individual frack stages. “The evolution over the last five years of piecing together this data has helped us to better understand our footprint and get to the point of where we’re drilling and producing 1,000-bbl/d wells,” he emphasized.

“I think the future of this play will include defining which intervals of the San Andres Formation are the most productive and cost effective to target. Looking forward, longer laterals and more frack stages per well could prove to be more economic as they have done so in other plays. I’m not sure we’ve fully tested that point of no return or point of diminishing returns,” Bryant said.

“At the end of the day, it comes down to experimenting and understanding the risk vs. reward for each little tweak that you do,” he added.

Optimizing lateral design

The first iteration of Steward Energy was focused on an early entrance into the Delaware Basin in Reeves County and was backed by Natural Gas Partners (NGP). Steward Energy I was monetized in fall 2014 just before the fall in oil prices. “It was very fortunate timing,” Taylor said.

“With oil prices falling the way they did, it took a lot of introspection to decide what we should do going forward. With an upsized team and commitment from NGP, we worked our way into the horizontal San Andres in summer 2016 and began assembling a position. Now, our gross operated acreage is just less than 96,000 acres with net acreage of 80,000 acres in Cochran, Yoakum and Gaines counties in Texas and Lea County to the west in New Mexico in about six contiguous blocks.

“We were firm believers that oil prices would be lower for a longer time and didn’t want to get into another high-cost unconventional play. We wanted to find a way to utilize the technologies and talents we had for unconventionals and apply them to more conventional rock,” Taylor explained.

“We can optimize at 1.5-mile laterals. We’ve found that to be ideal based on oil recoveries. Pacesetter has drilled a 2-mile lateral in Andrews County that has seen some strong early results, so we may test one of those at some point,” he continued.

“Even with the recent increase in service costs and the drilling and completion (D&C) optimizations, we’re still drilling these wells for about $2.6 million for a one-mile lateral and $3.3 million for a 1.5-mile lateral. We average right at 110 barrels of oil equivalent per foot on a gross basis,” he added.

“For the economics, we’re generating a 60% ROR based on our price deck, which is pretty conservative. We started off at $46/bbl in 2017 up to $52/bbl in 2020. Typically these wells pay off in a 1.5-year time frame. Net present value discounted at 10% (NPV-10) net of capital is $3.5 million for 1-mile laterals and a little over $6 million for 1.5-mile laterals,” Taylor stated.

Steward Energy has noticed trends in increased lateral lengths and has focused on optimizing those laterals. Field rules allow the company to complete and produce a horizontal well at 100 feet. off the heel and 100 feet off the toe. “Ideally, we start from a surface location off the lease to be produced, and we get an exception from the operator of that adjacent section. When we land the lateral horizontally, we are just inside the 100-foot offset lease hardline,” he explained.

“We can really maximize our lateral lengths. In a 1-mile section, we can get a full 5,000-foot lateral, while in some of our early generation wells we were getting only 4,200 feet. We’re getting close to 7,500 feet of producing lateral in the 1.5-mile laterals. The increased drilling cost is minimal. It comes down to added stages in our completion,” he said.

As an industry, horizontal San Andres operators are still trying to figure the optimum places to land the wells. Getting the right recipe for an area depends on the rock type, what the saturation profile looks like and how you stimulate that. “You need to know your petrophysics before you stimulate. You can definitely over-stimulate your rock,” he warned.

Steward currently has 1.5 rigs running. The company is drilling primarily in its Bronco prospect, which it purchased from Manzano LLC in fall 2016. “We’re on schedule to drill 33 wells in 2017 after just a five-well program in 2016,” he added.

In looking at its capital requirements, Steward has a credit facility available to supplement cash flow from operations. “As we’ve ramped up activity in 2017, we’ve exceeded our cash flow, but should be drilling out of cash flow in the coming months. We have manageable drilling obligations coming up in 2018 and 2019 on several of our other prospect areas. That’s another thing I like about this play. Because these wells are drilled in as little as eight days, we don’t need an army of rigs to hold a whole lot of acreage,” he emphasized.

Observing the play unfold

Ring Energy sat back for about five or six years and watched as Pacesetter kicked off the play. Then Ring watched Forge Energy enter the play and then Parallel Petroleum LLC. “We were intrigued with what we were seeing. We let those companies work through the learning curve and refine their techniques,” Ring’s Wilson explained.

“Then once we were comfortable, we decided to step into the play in 2016. We started drilling our first three wells in August 2016—two 1.5-mile laterals and one 1.25-mile lateral,” he continued.

“That’s where it all got started. Those first wells came online in October 2016. Based on what we saw and the success we had with those wells, we went out Jan. 1, 2017, and picked up a rig and started to drill full time. So far this year [June], we are on our 15th well,” Wilson said.

Ring Energy is a public company that is debt free and operates from cash flow at this point. The company likes the shallow formation with most of its wells between 4,500- and 5,000-feet true vertical depth.

For its D&C costs, Ring looks at an all-in cost for a 1-mile lateral of about $2.2 million. For the 1.5-mile lateral, the cost is about $2.6 million.

There are a lot of vertical penetrations in the San Andres, and a lot of public information is available. “If we’re moving into an area where we’re not quite sure where the landing zone is, we will drill a science well, do some logging and coring, and then identify our target zone,” he continued.

The company was producing 2,591 boe/d from the CBP as of March 31. As of June 2017, the company had 97,604 gross acres in Andrews and Gaines counties with 87,000 acres in the CBP designated as horizontal.

“We’ve announced we were going to do a 22-well program this year. I think you will see us, at the very least, carry that one-rig program through the end of the year, which would add more wells. We would have been done with the original program in about September,” Wilson noted.

Roth Capital Partners’ White said Ring Energy is probably the most active public company in the play. White covers Ring Energy with a buy rating and a $20 target price.

“We think Ring Energy is well-positioned because they were already in the play drilling vertical San Andres wells before they undertook the horizontal development scheme. By this early positioning, the company has a very large acreage position, which gives them—in our opinion—a multiyear drilling inventory of horizontal San Andres locations,” he continued.

“Based on our cash-flow numbers and Ring’s announced capex plan, we feel Ring will be very close to being cash-flow neutral in 2017. Another factor of Ring that we like is its solid balance sheet. As of March 31, 2017, it has no debt and a healthy cash balance,” White emphasized.

Technology enhances completion design

“We started working the play in fall 2013 when we identified the opportunity and started a leasing program,” Elk Meadows’ Dobkins said. “It took us about a year to get started and put leases together. We began drilling our first well in December 2014.”

Since then the company has continued to build its acreage position and begin development. “We have now drilled 12 producing wells and two SWD wells, although the last two wells are waiting on completion at this time. The primary field where we’re drilling is Dempsey Creek Field on the northwestern edge of Fullerton Field,” he continued.

Fullerton Field produces primarily from the San Andres and Clearfork formations. The field was discovered in 1942 and has produced more than 300 MMbbl.

“We’re playing off the edge of Fullerton Field. We drilled our first 10 wells in Dempsey Creek Field. Then we started leasing a little bit to the west of Dempsey Creek in another field called Tex-Mex,” he continued.

Dobkins compared the Elk Meadows wells to those that were drilled by Forge Petroleum Corp. in 2013 to 2014 in Shafter Lake Field and by Manzano and Walsh Petroleum and others in Yoakum County. The Elk Meadows wells tend to come in between 200 and 500 bbl/d during the first month.

“We’re about 4,500- to 4,600-feet true vertical depth into the upper part of the San Andres. We’ve been drilling 1-mile laterals except for one well where we drilled a 1.5-mile lateral. That turned out well enough that we’ll do more of them. But right now, we’re still drilling 1-mile laterals,” he said.

The San Andres is tricky, he stated. “We spent a lot of time and money on studying the rocks and structure. We’ve done a lot of mapping and understanding what the structures are. We’ve also done a lot of oil in place (OIP) calculations. We believe that OIP and structure are both very important in making economic wells. We have used that knowledge for driving our acreage acquisition.”

Technology is critical to making this play work and understanding the rocks. Elk Meadows uses 3-D seismic and a mass-spectrometer continuous logging tool to provide valuable data about the type of rock and fluids that can be expected, Dobkins explained.

“We try to land in the best rock and stay there. The mud logs and mass spectrometer are a big part of that. We’ve done some microseismic work to find where our fracks are growing, where we are staying out of the water and what we can do to try to reduce our water cut and get a higher percentage of oil,” he said.

“It is a whole lot easier if we plan the spacing early and don’t have to change it. The dolomite creates a different completion setup than shales do,” he emphasized.

The economics look very good for the company with average estimated ultimate recoveries (EURs) of about 400,000 bbl. “For a $2.5 million to $2.8 million well that gives very nice economics. The critical part is to watch our operating costs and try to keep costs down,” he continued.

Our early wells “are doing better over time than I thought they would. The declines are flattening out faster than I expected, and the EURs are going up over time. I’m even more optimistic than I was a year ago,” Dobkins said.

Finding the horizontal economic limit

Monadnock has 60,000 net operated acres situated adjacent to the most prolific fields on the CBP, including Levelland, Slaughter, Brahaney and Wasson. “We do have a lot of acreage. We’ll find areas that we can focus on and areas that we will probably let go to whittle down the 60,000 acres to something a little more manageable,” Monadnock’s Gentry noted.

“When you look at those fields, they have these large, broad TZ zones situated below the main pay zones. Historically, these fields developed vertically. At the first sign of water people would stop drilling, stop producing and only produce the main pay zones with the vertical wellbores as they reached the downdip economic limit of these wells. They would cease stepping out,” Gentry said.

The company found that it could go beyond those historical vertical wells with a horizontal well and access oil reserves in those TZs. “Through the use of modern technology—mainly horizontal drilling and fracture stimulation—we are able now to go find the downdip horizontal economic limit in a lot of these old historic fields,” he added.

Monadnack was getting ready to drill its ninth horizontal well in June. The company has already drilled three deep SWD wells. “One of the key aspects of the play is how cheaply and efficiently you can move and dispose of water. Without cheap disposal this play really wouldn’t work,” he continued.

“The old adage is the best place to find oil is in an oil field. That technological pendulum [with horizontal drilling and hydraulic fracturing] swung swiftly to the worst rocks—the shales—and really bypassed a natural progression in the evolution of a technology for these unswept transition zones off these oil fields,” Gentry said.

The company was funded in August 2015 with $100 million from Kayne Anderson Energy Funds. Monadnock was operating one rig in June and planning an accelerated drilling program in the second half of 2017. The company’s production was about 1,000 bbl/d. “Our best wells come on in the 300 to 400 bbl/d range. We typically see oil cuts as low as 5% to as high as 20%,” he continued.

The variability in the San Andres can be seen in the IPs. For a high oil cut, a typical IP is 300 to 400 bbl/d, and 200 to 300 bbl/d is typical for a lower oil cut. “Given the heterogeneity, variability in the play and rock quality you’re seeing, it is not a one-size-fits-all approach. It is really area specific. We’re using much smaller total volumes of proppant and fluid than the shale plays. That’s why our cost levels are so much different than a shale play,” he explained.

“Clearly it is a very attractive play because it is a lower-cost model than the shale model. Our well costs are in the $2 million to $2.5 million range right now. In that range at $50 oil, we are able to get RORs between 50% and 100%,” Gentry said.

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