Privately held Jones Energy Ltd. went to work on the Cleveland tight-gas sandstone in late 2004 after watching the larger, publicly held operator EOG Resources Inc. apply cemented-liner completion technology in its laterals in the formation for a year.

News reports often cite EOG’s work in the play as well as that of behemoth Chesapeake Energy Corp., but few know that Jones Energy nearly owns it. It’s drilled 162 operated horizontals into the silty, laminated sands that sit 7,000 to 8,000 feet deep—just above the long-plied Upper Morrow—and host a thin section of shale in some areas.

Jones currently has 158 wells producing from Cleveland, and receives a share of gas, gas liquids and oil output from an additional 55 nonoperated wells. The company has interests in 140 sections over the play with gross thickness ranging from a few feet up to 80 feet. Bottom-hole pressure is 2,500 to 3,000 psi. Permeability is very tight, averaging 0.01 millidarcy, and porosity is 8% to 10%.

The play covers some 650 square miles and is currently estimated to hold total reserves of more than 1 trillion cubic feet of gas equivalent in Ochiltree and Lipscomb counties in the northeastern Texas Panhandle and in western Oklahoma’s Ellis County. Jones also owns acreage over the nearby, hot-topic Granite Wash conglomerate that consists of as many as 11 members at different intervals, ranging from siltstone to cobblestone. There, it has one rig at work in the play.

The greater share of its five-rig effort is over Cleveland, a sand that just keeps giving, and particularly in the oilier area of the play, in Ellis County. “We’ve been very quiet and people are surprised by the number of rigs we have running in Cleveland,” says Mike McConnell, president of the Austin, Texas-based E&P. “Of the 18 rigs working the play in the three counties, four are Jones’.”

This year, Jones will drill 38 Cleveland horizontals, spending some $90 million. Wells cost $2.5 million, up from about $2 million in late 2009 before the company pushed its program to 20 frac stages, and as completion costs onshore the U.S. have grown some 40% in 2010.

In Ellis County, Jones’ nine-frac-stage wells have an average 30-day, initial-production rate of 1.7 million cubic feet of gas and 172 barrels oil per day. “We’re seeing multiples of that in the past dozen wells with 20-stage fracs,” says Stephen Roberts, Jones senior vice president, engineering. “The average oil IP number should go up significantly in the next few weeks and months.”

Jones’ nine-frac-stage Cleveland wells were proving an average estimated ultimate recovery (EUR) of around 1 billion cubic feet of gas and more than 70,000 barrels of oil in Ellis County.

Spacing is five laterals per section. “Early on, people thought the Cleveland was 320-acre-type drainage and then 160,” Roberts says. “Our goal is four to five long laterals per section based on net pay and volumetrics.”

Of the natural gas liquids (NGLs) content from Jones’ Cleveland wells, about 45% is ethane. “We’ve had no take-away capacity issues for the liquids,” McConnell adds. Jones sells all dry- and wet-gas production to three take-away providers—PVR Midstream, DCP Midstream and BP Plc—on a percentage-of-proceeds basis, with NGLs fetching above 50% of the Nymex price for West Texas Intermediate. “It’s a very good play for us right now.”

Making the Play Work

After watching EOG’s horizontal-drilling results in the Cleveland, Jones, which had been making conventional Morrow and dolomite horizontal wells in the area for years, evaluated EOG’s results and drilled its first horizontal into Cleveland in late 2004. “We jumped straight into a horizontal-drilling program,” Roberts says.

Some of this early drilling was on a 40-section farm-out from ExxonMobil Corp. in Lipscomb County. At year-end 2009, Jones acquired Crusader Energy Group Inc. out of bankruptcy for $240 million, and gained another 60 sections, these in Ellis County.
Jones had drilled just north of the Crusader acreage with EnerVest Management Partners Ltd. in the past. “So, we knew the area well and this acreage looked very similar to the Cleveland that’s just north of it,” McConnell says.

Both Jones’ drilling and completion best practices in the play have evolved during the past six years of prodding the sand. “We’ve probably made more than 100 small changes over time to accommodate new technology and innovation,” Roberts says.
In drilling, its most significant change was almost immediate: using PDC bits instead of rollercone, button-type bits. “PDC bits had begun to work their way into the industry and into some of our Morrow wells.” With the PDC technology, Jones’ drill time has declined from more than 30 days to about 22, and while drilling longer laterals.

“We typically will drill the vertical portion to kickoff point of the curve 8,000 feet in eight days or less or 7,000 feet in seven days or less, and so on. In the lateral section, we generally average 600 feet a day,” Roberts says.

In the early years of PDC bits, they would easily cut shale but were prone to deviation and would dull quickly when encountering limestone and sandstone. “Today, however, after working with our vendors, primarily Baker Hughes, we have improved the design to drill straighter and handle a variety of formations. A single PDC bit can be used in each section of the well—vertical, curve and lateral.”

Jones’ laterals are some 4,000 feet lately. “We just did an internal study on extended-reach drilling,” McConnell says, “and we’re looking at the results in the Bakken (play in North Dakota) where they’re using super-long laterals and 40 or more frac stages.” For now, however, “we are very satisfied to continue our 4,000-foot laterals and 20-stage, Packers Plus-type completions.”

Its stimulation program was revised just three Cleveland wells in. “We watched EOG to understand how they were doing a cased-hole, perforation-type completion and how they were isolating their case perfs,” Roberts says. Jones decided to try the somewhat nascent Packers Plus technology instead, which allows openhole completions while still isolating lateral intervals and fracing each individually. “People thought we were a little crazy, doing this open hole,” McConnell says.

The first application was not a resounding success, but “the second two wells worked like a charm. Now, we are 162 wells into our program and, with the exception of three case perfs, we’ve done 159 Packers Plus jobs.”

At first, three or four frac stages with Packers Plus “seemed like pushing the limits,” Roberts says. They were enough for the short laterals of the time, but Jones pushed for more. “When it was clear that longer laterals and more fracs would yield better EURs and be more cost-effective, we asked for nine and then 15.” And then 20, which it rolled out earlier this year and has applied to 15 wells.

Jones also changed its mud program over the years in some Ellis County wells that have stubbornly resisted the bit in the curve into the lateral, from a 9-pound, freshwater mix to an oil-based mud.

Leveraging Scale

While service costs are narrowing producers’ margins across the U.S., including Jones’, the company is able to leverage its scale in the play, McConnell says. “Prior to 2010, we averaged 14 days from rig release to gas flow. Today, that has become more problematic. We could keep rigs and frac crews at work nearly 24/7, particularly while doubling frac stages, using twice as much CO2 and sand.”

Halliburton does Jones’ frac jobs currently. “We have had a lot of luck with not having to wait for fracs but that has changed recently, and it requires more careful planning,” Roberts says. “Larger fracs have stressed the system.”

McConnell quantifies Jones’ scale in the Cleveland: “We have done 1,366 individual fracs since we started in this play, and we have drilled just shy of 500,000 feet of laterals—about 92 miles. Those are significant numbers for a small company.”

And, it leverages its relationships. Jones experimented with a product similar to Packers Plus to check its cost competitiveness. “It worked about as well,” Roberts says, “but Packers Plus has been tried and true for us—for almost 160 wells and almost 1,400 individual fracs.”

The Jones team also knows the system like one of its own. “We have a completion superintendent who has completed every one of our wells. He has seen this for six years and understands the system in and out.”

McConnell says, “You have to have a partnership attitude in everything you do.” The company has drilled more than 130 wells on its farm-out from ExxonMobil, and more than 40 with BP Plc. Other partners include ConocoPhillips, Devon Energy Corp. and Samson E&P. “Not only do we drill cost effectively and use the latest technology, we drill very safely. People in business with us trust us. And, what we know, they’re going to know.”

McConnell expects continued weighting of its attention to its more liquids-rich Ellis County acreage. “Today, the difference in crude and natural gas prices is 17 to 1, and that tells us to drill oilier Cleveland areas. We are very fortunate: We have 250 identified locations to drill. We can look at all of these locations and drill the ones with the best economics of the day.”

About 29% of Jones’ total Cleveland volume is NGLs currently, and 31% is oil. “When you look at the revenue stream with the current ratios, oil and NGLs represent 77% of the revenue,” McConnell says.

The company’s production is almost entirely hedged, including a large portion of the NGLs lately. “We have price protection to assure we can continue drilling.” Many of the hedges were put in place when it bought the Crusader package for cash. Wells Fargo leads its bank syndicate. “We locked up 90% of our crude and natural gas for five years.”

Will Jones take its Cleveland laterals out farther and add yet more frac stages? “That question is being asked internally all the time,” McConnell says. “What is the proper distance between frac ports? Historically, it has been around 350 feet. We’re showing now that that was too long. We’re probably averaging 180 feet right now and maybe it should be 100.”

Jones holds about 90,000 contiguous net acres over Cleveland and a majority interest, and is operator in all 140 sections. “We like to drill and operate, especially in areas where we think we’re very good at it and have a competitive advantage.

“Some companies find it is better to let us drill and keep a percentage without a lot of promote. We are always the operator to drill; that’s very important to us.”

Best practices in the play will continue to evolve, McConnell and Roberts forecast. “Since we spudded our first well in December 2004, we’ve really changed our view of this play a lot. We’ve challenged our own dogma. Just when we think we have this play figured out, the play will tell us that we don’t.”

Paying attention to the margin is still the biggest challenge. “Luckily, we hedged our production. At times, drilling costs are too high, and that’s something we always pay attention to—that cost versus what we get for our production. Our key challenge is watching that very carefully, always.”

Some small producers, particularly private ones, drill to sell, making a few holes across their leasehold, proving a play and then selling to an operator that will develop it, particularly a public company that needs to replace reserves and production quarterly.

Instead, Jones, which was formed in 1988, develops its leasehold. “We look at a play to drill it,” McConnell says, “like we’re going to drill it all.”

The company does sell at times, primarily to deploy the cash in acreage that has captured more of its attention. It’s had three significant sales, including its Ellis County interest with EnerVest to Noble Energy Corp. in 2008 for $290 million, deploying the money in Lipscomb County; and its Hansford County, Texas, production and acreage to Randy Foutch’s Laredo Petroleum LLC in 2007 for $75 million, forming the foundation for Foutch’s third buy-and-build iteration in partnership with Warburg Pincus. Jones’ first asset sale was properties in Hoover Field in Roberts County, Texas, to Newfield Exploration Co. for $26 million.

“We have been blessed with a lot of opportunities to spend money on great plays,” McConnell says, “probably more opportunities than capital, although we are in very good shape capital-wise. We do monetize if the market says that’s what we need to do, and maybe the Cleveland is one of these at some point. Monetizing is important, but it’s not our only driver. To drill three wells and sell it, that’s not been our company mantra.”

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