Natural gas prices have not been kind to E&Ps in recent years, and the impact of low prices has tended to be felt disproportionately by those far from major markets. Hedging can help offset what in some cases are wide regional differentials, but it is basin-specific geology that often plays a key role in ultimate economics. In this regard, the greater Green River Basin (GGRB) has been no exception.

Historically, activity levels in the GGRB have trailed that of other basins for several reasons, including its geology. The geologic makeup of the basin includes a thick, gas-charged section, but the formations—typically sandstones, siltstones and shales—are often discontinuous. These types of reservoirs can often be challenging to tap via long lateral horizontal drilling.

In addition, as it is well-known, production in the basin leans heavily toward natural gas, and gas prices in the region have historically traded at a discount to Henry Hub. Going into September, for example, the natural gas price at the Colorado Interstate Gas (CIG) hub in Wyoming was at roughly a 70 cent per thousand cubic feet discount to Henry Hub.

Some attribute a modest level of horizontal drilling in the basin to not only geological factors, but also the fact that there have been fewer E&P entrants and, as a result, less innovation. As of September, the number of producing horizontal wells in the GGRB remained relatively small, at about 120 wells, according to figures from the Wyoming Oil and Gas Conservation Commission.

However, E&Ps are finding ways to boost the basin’s economics and offset the impact of lackluster gas prices.

For some, it’s a strategy that includes modifying drilling programs to introduce or increase the number of wells drilled horizontally. An incentive is that some horizontal wells are producing several times more liquids than their vertical well counterparts. Of course, a higher liquids component tends to help boost E&Ps’ blended realized prices, especially with NGL prices showing strong gains recently.

The Lance and Mesaverde

Denver-based Jonah Energy LLC has drilled more than 400 vertical “directional” wells since its inception, but has been gradually adding a horizontal well component to its program. The company is allocating 75% to 80% of its 2018 capex to a traditional diet of vertical wells. The remaining 20% to 25% is for drilling horizontal wells mainly in the Lance Formation, incentivized by a markedly higher liquids component with horizontal wells. Jonah Energy expects to drill seven horizontal wells in the Lance by the end of this year. According to its CEO, Tom Hart, the liquids component of a horizontal Lance well is roughly two times that of a vertical well. In addition, Jonah Energy plans to drill one well this year in the Mesaverde Formation, in which liquids may make up three to five times that of a vertical Lance well.

“Our pursuit of horizontal opportunities is driven in part by just the mechanics of horizontal drilling—accessing more stimulated rock through a horizontal lateral rather than a vertical—and part of it is also the economic contribution of the liquids in these wells,” said Hart. While liquids made up only 16% of the company’s current output, they accounted for 40% of unhedged revenue in Jonah Energy’s second quarter, he noted.

“We’ve really just scratched the surface,” with only about 20 horizontal wells drilled in Jonah Field and the Pinedale Anticline, according to Hart. The two adjoining fields—Jonah and Pinedale—together have had cumulative production of around 12 trillion cubic feet equivalent (Tcfe). However, this came only from a handful of E&Ps: chiefly Jonah Energy, Ultra Petroleum Corp. and Oak Ridge Natural Resources LLC.

“Historically, in the area, you didn’t need to drill a horizontal well to make a very competitive well,” he said. “It’s amazing that at today’s prices, we’re still drilling vertical wells with such strong economics.”

Jonah Field continues to offer years of good inventory of vertical drilling at attractive economics, Hart emphasized. “We can drill a $2-million vertical well and get an EUR of 2 to 4 Bcfe, with 40% of our revenues coming from liquids,” he said.

The area where Jonah Energy plans to focus its horizontal drilling lies mainly on the downdip (north) side of Jonah Field, where much of the acreage was acquired from Linn Energy Inc. (See Oil and Gas Investor, July 2017.)

“We expect to be drilling more Lance horizontals there because the area has had very little vertical development. There’s still a lot of resource that can be developed horizontally and has economics that surpass vertical well economics. If we can have consistency and repeatability, and we get a higher liquids contribution, it will be among our best inventory,” observed Hart.

Providing further Lance horizontal details, he continued, “We think our ability to get 75% net to gross sand in the wellbore is achievable as a repeatable average. We think that is probably around 3 Bcfe of reserves per 1,000 feet of lateral. If you have a 10,000-foot lateral and 75% of it is in sand, that 7,500 feet in sand gives you an EUR of 22 Bcfe or so [3 Bcfe times 7.5 equals 22.5 Bcfe] with a substantial liquids contribution,” he calculated. “That’s the prize of the Lance horizontal for us.”

Jonah Energy also sees potential for horizontal Mesaverde development in much of Jonah Field, where it would benefit from existing infrastructure.

“We really like the Mesaverde. We see it as a big contributor to our liquids, which ends up being a big driver of our economics,” said Hart. “There’s been very limited penetration of the Mesaverde Formation, because previous vertical wells were generally drilled to the base of the Lance or only a short distance into the Mesaverde, which averages about 1,000 feet in total thickness. That’s a big resource opportunity, right where we’re already operating 2,300 vertical wells.”

Confidence on the part of Jonah Energy is based on early work involving vertical tests of the Mesaverde. “We have confidence because we started drilling to the base of the Mesaverde in vertical wells and got really good production data,” said Hart. “We’ve isolated the Mesaverde, fracked it and produced it, before going back to complete all the other zones.”

Results from the first horizontal Mesaverde test are expected by year-end, and “that will influence how much capital we devote to it,” he continued. “It’s more of a resource rock. There’s a thick section, and we would expect the potential for multiple benches. We’ll take it little by little. Hopefully, we’ll have success in one bench and then see if we can expand it to other benches.”

Normally Pressured Lance

Jonah Energy’s move toward horizontal drilling comes as the company received a record of decision regarding a final environmental impact statement (FEIS) on its Normally Pressured Lance natural gas project in late August. The end of the seven-year process signals the go-ahead for developing acreage—informally the “Jonah Extension, or JEx”—to the south and west of its current production.

The development project involves an area of about 140,000 gross/115,000 net acres. Jonah Energy has proposed drilling up to 3,500 directional gas wells during the next 10 years, although the well count may be lower to the extent it includes a component of horizontal wells. The project could unlock up to 7 Tcf of natural gas, according to the FEIS notice by the Bureau of Land Management (BLM).

The new development project is also expected to provide a mix of vertical and horizontal opportunities.

“We think a real opportunity exists to take the horizontal technique and apply it to various formations as you move south and west across the JEx acreage,” said Hart. “We’ll probably target the Lance and Mesaverde first, because they’re the best understood and don’t involve risking a lot of capital. The trick for us is de-risking these things at a pace where we don’t put our financial strength at risk.”

Hart noted that the acreage is largely “virgin territory,” without much vertical development. Longer term, he said, there may be an opportunity to test deeper formations, for example, the Rock Springs or Hilliard Shale, which are potential resource plays that underlie the entire block with a combined thickness of several thousand feet. Such tests would aim to evaluate the economic potential of the intervals, which could create significant drilling inventory. In terms of hedging its production, Jonah Energy is very active, including hedging of basis for Northwest Pipeline vs. Henry Hub. For the last quarter of 2018, it has around 100% of production hedged, at 34 cents off Henry Hub. (This is narrower than for the full year, given the coming winter months.) For 2019, it was also heavily hedged, at 43 cents off Henry Hub, vs. strip pricing of around 65 cents.

Sweetwater County

Elsewhere, the industry has recently been active in picking up acreage, with the Wyoming State Office of the BLM drawing high bids for parcels in Carbon County and, in particular, Sweetwater County at its June 26 and 27 lease sale. Notable were $16.2 million in high bids by Southland Royalty Co. for 52 parcels, including 41 in Sweetwater, as well as $13 million in high bids in Sweetwater by Black Oak Energy LLC.

Industry observers have sensed an air of optimism surrounding Sweetwater and nearby acreage.

“I think there’s definitely a sweet spot for activity in Sweetwater County, where Southland Royalty and BP are located,” said Geoff Roberts, head of U.S. A&D with BMO Capital Markets. “They’re going after the Lewis Formation. It’s more conventional; it’s not a resource play. There are going to be sweet spots where you’ll be able to generate 100%-plus internal rates of return.”

IHS reports offered a confirming view of the recent BLM lease sale. “The results of the June 26 and 27 BLM sale have validated the rise of, and industry interest in, the horizontal Lewis/Fox Hills/Mesaverde gas/condensate play in the Great Divide and Washakie basins,” commented Bob Knowles, who covers industry activity in the western U.S. for IHS.

Southland Royalty has had success lately with horizontal wells targeting a variety of zones. Earlier this year, Southland’s 15-33-4H Chain Lakes well flowed at an initial rate of 945 barrels per day (bbl/d) of crude and condensate, plus 8.2 MMcf/d of natural gas, from a horizontal producer to the Lewis Formation. The well is in a field off the northern flank of the Washakie Basin, according to IHS data.

Southland Royalty and BP America Production Co. have now drilled nine horizontal producers on the companies’ Chain Lake leases. Targets range from the Lewis (five wells), to the Fox Hills (three wells) and Mesaverde (one well). Four wells were drilled by Southland, including the 15-31-1H Chain Lakes well, a late-2017 Lewis producer, which initially flowed 353 bbl/d of crude and condensate and 5.4 MMcf/d of gas.

The more recent 15-33-4H Chain Lakes well is estimated to be about 18 miles north of Wamsutter, Wyo. The earlier well drilled by Southland, the 15-33-1H Chain Lakes, lies some three miles to the west of it.

Milagro Federal Unit

For Samson Resources II, the focus of s GGRB activity has been on some 30,000 net acres in Sweetwater County, where it recently consolidated its position with a $15.9-million acquisition of nonoperated assets. Targets in the Fort Union—a “very liquids-rich reservoir”—have delivered highly competitive results in what is primarily a natural gas basin, said Samson CEO Joe Mills.

In total, Samson has nearly 50,000 net acres in the GGRB. Some of its acreage extends eastward into Carbon County, where Samson continues to evaluate its potential. Output in the GGRB is currently “just shy of 3,700 boe/d,” but set to rise rapidly as Samson forms its proposed 25,000-acre Milagro Federal Unit. Downspacing tests for pad drilling are underway at about 20-acre spacing, yielding almost 850 current locations, and Samson holds out the possibility of 10-acre spacing, doubling the potential location count.

“It’s a really great position,” said Mills. “We think what we have in the Green is a little gem. We’re likely to buy out a few more partners by year-end, taking our working interest to close to 95% across our position in the play. We really like this asset in the Washakie Basin.”

Samson’s predecessor company began assembling its current GGRB acreage in 2008 and continued through 2011. The company was targeting the Fort Union, with its “liquids-rich, almost 1,000-foot column of hydrocarbon-charged sands,” recalled Mills. Initially, it drilled vertical wells, and then tried horizontals, only to return to a vertical program after its predecessor company encountered issues in drilling and well costs that reached $15- to $17 million.

“What they found was that drilling was particularly difficult because it was a fluvial environment and, because there were compartmentalized channels, they had trouble staying in zone,” he explained. “They had a lot of sidetracks. You also had a lot of mud losses drilling these wells, which led to getting stuck quite a bit. It was a very challenging drilling environment.”

In later returning to the play—and knowing that technically successful wells could deliver up to 4,150 boe/d (ca. 25 MMcfe/d)—Samson switched back to a vertical program with a key change to the completion recipe, according to the Samson CEO. In place of legacy wells having three stages with 400,000 pounds of sand per well, a new completion design of 12 stages and 1.4 million pounds of sand per well was used.

Fort Union wells

The result was “the two best vertical Fort Union wells drilled in a very large area,” in a four-well pilot, said Mills. Called Gen-2 wells, the 11V Barricade and the 16V Barricade are expected to produce two and three times as much as legacy vertical wells, respectively, based on a 90-day test. Initial 30-day flow from the 16V well was put at 238 bbl/d of oil and 6.25 MMcf/d of gas. The well has produced an average of 184 bbl/d of oil and 6.17 MMcf/d of gas in the first 90 days.

“We knew a liquids-rich gas resource was in place and that it had high deliverability,” he said. “We realized this had the potential to be a gas manufacturing play, and it was all about driving the cost structure down. The 16V will be almost 2.5 times better than anything we’ve drilled before and at a very, very reduced cost.”

Currently, the cost of a vertical well is estimated at around $4 million, with a line of sight on $3 million in pad development, according to Mills. In equivalent terms, the 11V Barricade is estimated to have an EUR of about 660,000 boe, while the 16V Barricade—called an “absolute barnburner”—is estimated to have an EUR of 1.25 MMboe. The IP-30 rate for the 11V averaged 172 bbl/d of oil and 3.89 MMcf/d of gas.

Deeper tests to Lance and Lewis

Virtually all Samson’s GGRB capex is earmarked for the Fort Union in 2018. However, with projected capex roughly doubling to $100 million in 2019, Samson plans to add a second rig, so it can continue delineating the Fort Union, as well as test some of the basin’s deeper horizons. A likely program would be four to five deeper tests, with the Lance and the Lewis each getting two or more.

In its earlier drilling campaign, Samson’s predecessor company did, in fact, drill several wells in the Lewis, which is situated below the Lance and above the Mesaverde. One well, the CEPO Federal 20-17, is estimated to have an EUR of approximately 14.8 Bcfe. “It was our best well in the field to date, so we know the Lewis is a productive horizon,” commented Mills.

Liquids from the Fort Union make up about 53% of production, with the NGL stream tilted to a lighter barrel comprised of a greater ethane component, according to Mills. This continues to help Samson’s blended realized prices, since ethane prices have strengthened to around 60 cents per gallon as of late-September, up from around the 25 cents level at which ethane meandered for much of the last several years, he added.

For gas processing as a whole, Samson has a long-term arrangement dedicating volumes to Western Gas Partners LP, whose assets include facilities in close proximity to the CIG natural gas pipeline. Western Gas redelivers gas to CIG at a tighter differential than in some Wyoming regions. As of September, Samson’s year-to-date net gas price has averaged $1.92/Mcf, while its NGL sales price has averaged $21.34/bbl.

For crude and condensates, the year-to-date price received by Samson has averaged $64.45/bbl.

Weighing options

One factor that Samson is likely to address relates to its predecessor company’s bankruptcy, leaving its second lien group as the new equity shareholders. The company is weighing its options.

“At some point in the near future we will decide if we will monetize some or all of our assets in the GGRB and Powder River Basin in order to deliver cash to our shareholder base,” said Mills. “We remain very excited about the underlying potential of both of our assets. As we weigh strategic options, one question we’ll evaluate is whether to remain a going concern by going public, or to monetize the company, either as a single entity or separately in order to maximize the value of our two assets.”