The Niobrara

HP Flex Rig #315 is tripping pipe on Noble Energy Inc.’s #13-99Hz Gallegos PC in Weld County, Colorado.

The widespread, oil-rich Cretaceous Niobrara formation has produced for decades from localized fractured areas in the Rocky Mountain region. Now, today’s shale exploitation techniques are affirming fresh potential in this tempting, chalky source rock.

Just a few years back, Paleozoic shales were all the rage. The Mississippian Barnett and Fayetteville shales and the Devonian Woodford and Marcellus dominated attention. Anyone in the industry interested in shales pondered the well-known map of the Ouachita fold belt and its associated shale deposits.

Younger shales were on the sidelines, somehow judged not quite ready for prime time.

Now, however, it’s the Age of Cretaceous. The Eagle Ford shale play in South Texas is firmly in the limelight, and the Niobrara is a talented understudy ready to break into the big time. Certainly, when the Jurassic Haynesville is added to the mix, Mesozoic shales are the wunderkinds of this decade.

The newest focus of oil-prone shale explorers is the Niobrara formation, particularly in the Denver-Julesburg, a huge sedimentary basin that inhabits Colorado’s eastern plains and swaths of southern Wyoming and western Kansas and Nebraska. Leases are being snapped up, deals are being done and rigs are turning to the right.

The Niobrara is on the cusp.

Pipe lays on the rack at the horizontal Niobrara test in Grover Field. Projected measured depth is 11,456 feet on the Gallegos test.

The Jake Debut

Houston-based independent EOG Resources is widely appreciated as a leader in exploration and exploitation of oil-prone resource plays. It is also famously tight-lipped, declining to speak publicly about its endeavors. Nonetheless, every so often it holds analyst meetings that give industry observers some in-depth information.

In its latest such presentation, in April, the company talked in some detail about its Niobrara efforts. And, to assuage the curious, it released particulars on its splendid Jake well.

In third-quarter 2009, EOG drilled a horizontal Niobrara well, the #2-01H Jake, in Weld County, Colorado. The company had already been active in the Niobrara in North Park Basin, farther west in the state. But the Jake, its first Niobrara test in the DJ Basin, was a barn-burner. It produced at a maximum rate to sales of 1,558 barrels of oil per day from a 3,800-foot lateral, and made 50,000 barrels of oil in its first 90 days on production.

The Jake well was the talk of Denver for months, and it had caused interest in the Niobrara to soar.

Encouraged by its success at the Jake, EOG drilled four more horizontal Niobrara wells in Weld County, and it talked about these also. Its second test, #8-31H Elmer, produced at a maximum rate of 730 barrels of oil per day from a 2,000-foot lateral. The lateral was shorter than projected due to hole problems. Its third well, the #10-16H Red Poll, featured a 5,200-foot lateral and was an unstimulated openhole test. It came on flowing at a maximum rate of 1,100 barrels of oil per day. It was declining and had not stabilized at the time of EOG’s investor presentation. Its fourth and fifth wells, #2-01H and #4-09H Critter Creek, encountered encouraging pressures and were working toward completion.

“We feel there may be multiple Niobrara core areas,” said Kurt Doerr, executive vice president and general manager of EOG’s Denver division, at the April presentation.

The Niobrara is very complex, he noted. EOG uses 3-D seismic to enhance its geologic model and provide specific drilling targets. It also uses managed pressure techniques to drill its laterals, and completes its holes with swell packers and stage-fracturing technology. While overpressuring in the Niobrara is relatively minor, the formation’s extensive fracture systems dictate the delicate approach.

The operator has 400,000 net acres in the DJ Basin, and continues to lease in specific areas. It is keeping two rigs busy drilling Niobrara tests. Well costs are $3.4 million apiece, but the company emphasized that its Niobrara program is in its early days, and its strategies are fluid.

“So far we have seen strong initial results; the wells have not had enough long-term production to make reasonable reserve estimates,” said Doerr.

EOG took its leases in an area with a marked fracture overprint, and its pressing question at present is whether the Niobrara will be a high-rate fracture play only or if matrix contributions will be significant, he noted.

Horizontal Niobrara activity is red-hot in the Denver-Julesburg Basin, and explorers are evaluating the Cretaceous shale in other Rockies basins, particularly those with histories of vertical Niobrara production.

Wattenberg and Beyond

While EOG’s Jake well fueled the initial horizontal Niobrara frenzy in the DJ, other companies were already deep into their own Niobrara programs. Noble Energy Inc., the largest producer in 1.9-million-acre Wattenberg Field, has focused closely on the calcareous shale for years.

Houston-based Noble Energy likes a diversified and balanced portfolio that allows it investment choices, says David Stover, president and chief operating officer. “Onshore U.S. is one of four key components of our portfolio, anchored by the Wattenberg area. The onshore business provides us both near- and long-term growth.”

The Niobrara is particularly attractive because it supplies two elements quite in demand these days: significant running room and a high liquids component. When those attributes occur coincident with an enormous position such as Noble Energy holds, so much the better.

The unique reservoir combines development—the traditional role of mature, onshore assets—with substantial exploration potential. “The Niobrara is an area that can really take off for us,” he says.

For a number of years, Noble Energy had been looking to expand its onshore activity. “We wanted to find an underappreciated area where we could build a position that could have a significant impact on the company,” says Stover.

In truth, that very opportunity was within the DJ Basin where Noble Energy has been operating for a number of years. Noble decided to move on the Niobrara and quickly bolted on new acreage to complement its core Wattenberg holdings.

Niobrara production. By year-end, Noble Energy will have enough information across its 750,000-acre Niobrara position in the DJ Basin to see where it wants to take its program, says David Stover, president and chief operating officer.

To date, the company has amassed 750,000 net acres in the Niobrara, in two geographic areas of the DJ Basin. Within Wattenberg Field, the independent holds 391,000 acres, says Ted Brown, senior vice president, northern region.

It has another 360,000 net acres extending north of Wattenberg into southeast Wyoming. Grover Field, some 10 miles south of the Wyoming border, is a current hot spot for its Niobrara exploration.

The company started experimenting with Niobrara completions and recompletions in 2004 and 2005. Today, it has some 4,700 vertical wells completed in the formation in Wattenberg, the largest producing field in Colorado. “We have developed a deep knowledge of the Niobrara’s reservoir characteristics, and we have gathered a vast array of data over the years,” says Brown.

From its work, Noble Energy concluded that vertical wells in Wattenberg drained less than 10 acres in the Niobrara. It put its efforts toward figuring out how to extract more of the tremendous in-place resources locked in the formation.

Horizontal wells were an obvious approach, although there were questions about whether they could be successfully drilled and fractured in the midst of densely drilled Wattenberg.

Last year, Noble Energy drilled four horizontal Niobrara wells within the confines of the field. “So far we are very encouraged with the horizontal well results,” says Brown.

One test, #1-99HZ Gemini K, in Weld County, is the best well ever drilled in Wattenberg’s long history. It produced 60,000 barrels of oil equivalent (BOE) in its first 60 days on line, and will ultimately recover more than 500,000 BOE. The well, threaded between eight producing vertical wells, featured a 4,000-foot lateral stimulated in 16 frac stages.

Altogether, the average of its four Wattenberg horizontals was initial production of 585 BOE per day and estimated ultimate recovery of 290,000 BOE. Certainly, the horizontals were unqualified successes.

This year, Noble Energy will drill about 25 horizontal Niobrara wells, of which 15 or so will be within Wattenberg Field, says Ted Brown, senior vice president, northern region.

In 2010, the company plans about 25 horizontal Niobrara wells overall, and 15 or so of these will be within the confines of Wattenberg. Noble Energy also continues an active program in vertical drilling in the massive field, running five rigs there. And it carries on an aggressive refracturing program in existing wells.

Ten Niobrara horizontals are planned on its exploratory acreage in northern Colorado and southeastern Wyoming. Already, it has initiated drilling on its leases outside of Wattenberg, with the campaign centered in and around Grover Field.

“We’re doing a lot of data gathering, to learn as much as we can,” says Brown.

The company sees variability in the Niobrara across its broad position. In the heart of Wattenberg, the Niobrara gas/oil ratio (GOR) is very high, typically between 20,000 and 30,000 cubic feet of gas per barrel of oil.

Within the field, Niobrara porosities run 12% to 14%. “We think that production within Wattenberg is dominated by matrix porosity,” says Brown. “The success of the play in this area is not necessarily dependent on finding large swarms of open, natural fractures.”

A worker readies a coil-tubing connection at Noble Energy’s #15-99Hz Furrow USX AB, a horizontal Niobrara test in Wattenberg Field.

To the north, however, porosities decline to 8% to 10%. While the Niobrara is overpressured within Wattenberg, exhibiting gradients of 0.55 to 0.5 psi per foot, pressures decrease to normal at Silo Field.

To the north and east of Wattenberg, the GOR decreases to 1,000. Because the Niobrara is much oilier in this portion of the play, artificial lift will be needed for sustained production.

Currently, Noble Energy is spending $3.5- to $4 million to drill, complete and equip a Niobrara horizontal well with a 4,000-foot lateral. Because its program is still in the exploratory/evaluation state, those costs include cores, high resolution logs and microseismic data. “We have an opportunity to drive costs down farther,” says Brown. The company is experimenting with various completion strategies, from swell packers to cemented liners with plug-and-perf strategies.

Already, the company has cut 20% from drill times on its horizontals, simultaneously increasing lateral lengths from 2,500 to 4,000 feet and more. “We have a tremendous amount of well control, and we use 3-D seismic to help steer our wellbores.” The operator has also increased frac stages threefold, to between 16 and 18 stages on a 4,000-foot lateral.

Frac sand flows into a blender during a Halliburton stimulation of one of Noble Energy’s vertical Codell/Niobrara wells in Weld County.

Noble Energy estimates that the Niobrara contains 20- to 30 million BOE per section. Based on recovery of 5% of oil and gas in place, and the possibility of 160-acre spacing for horizontal bores, it thinks recoveries of 300,000 BOE per well are possible.

“We think recoveries will increase as we experiment with optimal well placement, selection of intervals and various stimulation methods,” Brown says. “Our biggest challenge in the play right now is trying to increase recoveries.”

At an assumed 5% recovery of original oil and gas in place, Noble Energy has total unrisked potential of 1 billion BOE on its Niobrara acreage. “The Niobrara is long-lived, low risk and a liquids-rich opportunity,” says Brown. “We find it very attractive.”

By year-end, Noble Energy will have enough information across its Niobrara acreage to more fully understand the formation and see where it wants to take its program, says Stover. The real win for Noble will be full-fledged horizontal Niobrara programs both inside and outside Wattenberg.

“We’re learning as we go, and we’re learning fast,” he says. “The questions we want to understand by the end of this year are whether there will be sweet spots or larger areas of economic production in the Niobrara, and what producing mechanisms are needed for economic production.”

Rick McCullough, chairman and chief executive, PDC Energy, says the Niobrara play could transform the company.

Vertical to Horizontal

Another Wattenberg operator with Niobrara upside is Denver-based PDC Energy, which recently changed its name from Petroleum Development Corp. The independent has a major stake in the emerging play.

The company has been working in Wattenberg for years, mounting a Codell, Niobrara and J-sand program on a 64,900-net-acre position on the northeast side of the field.

PDC operates 1,410 wells in Wattenberg, says Rick McCullough, chairman and chief executive. “We’re fortunate that we have a very large position in Wattenberg, and a substantial portion of that—some 20,000 acres—is undeveloped.” Furthermore, PDC’s acreage is in the oilier portion of Wattenberg. “About 55% of our stream is oil and liquids, and 45% is natural gas,” he says. “Even in the low-gas-price window at present, our drilling economics feature rates of return around 40%.”

PDC figures its typical vertical well in the Codell and Niobrara in northeast Wattenberg costs $600,000 and recovers 23,000 barrels of oil and 150 million cubic feet of gas. Refracs, which mainly target the deeper Codell formation, cost an additional $180,000 and tap incremental reserves of 13,000 barrels of oil and 155 million cubic feet of gas. At Nymex strip prices posted at the end of May 2010, these wells yielded an internal rate of return of 43% on primary drilling including the refrac.

Bart Brookman, senior vice president, exploration and production, says PDC Energy has 70,500 net acres prospective for Niobrara. The operator will spud its first horizontal test in the shale later this year.

In the heart of Wattenberg, the Codell has been the heavyweight producer of the two formations, says Bart Brookman, senior vice president, exploration and production. PDC’s acreage is in northeast Wattenberg, where Codell reservoir quality is lower and the Niobrara could be contributing as much as half the reserves in commingled wells.

“Improvements in completion techniques and fluids have really enhanced Niobrara recoveries in the vertical wells,” says Brookman. “Our production from Wattenberg in 2009 and 2010 is exceeding our projections.”

This year, PDC will drill 165 vertical Codell and Niobrara wells, and perform about a dozen refracs. It has two rigs running in the field, and will add a third in the fourth quarter. It carries 1,500 vertical locations in inventory.

Now, PDC is evaluating its Wattenberg acreage for horizontal Niobrara potential. It has identified six to seven prospective acreage blocks within the field.

Recently, the company acquired 5,500 net acres of undeveloped leases about eight miles northeast of its Wattenberg blocks, bringing its total net Niobrara acreage to 70,500. The new block, the Krieger prospect, will be the site of PDC’s first horizontal Niobrara test. The expected spud is fourth-quarter 2010.

Overall, the company sees Niobrara potential across its entire leasehold. Although 45,600 acres are classified as developed, the very limited drainage areas of the vertical wells mean that most Niobrara hydrocarbons still reside in place.

Happily, Noble Energy’s success indicates that horizontal wells can be successfully overlaid in vertically drilled sections. “We think horizontal wells in Wattenberg will recover incremental reserves on top of our vertical proved undeveloped locations,” says Brookman. “That’s supported by the extremely low recovery factors.”

PDC figures it has 13 trillion cubic feet equivalent (Tcfe) of original gas in place on its leases (based on 20 million BOE in place per section). Assuming recoveries of 4.6%, it has potential for some 600 Bcfe of reserves, in addition to its current booked 3P reserves of 1 Tcfe.

There are really two stories in the Niobrara: what’s happening within Wattenberg, and what’s happening outside the field, says McCullough. Within Wattenberg, vertical wells in the Codell and Niobrara and horizontal Niobrara wells will both work. Outside the field to the north and east, the Codell is not present or is thin and tight, and horizontal wells will be the technology of choice.

“We’re a smaller company, but we have tremendous exposure to the Niobrara,” says McCullough. “We’re very leveraged to the play, and we see it as a transformational opportunity.”

Noble Energy is at work fracturing its #37 Dillard USX AB, a vertical Codell/Niobrara well in Wattenberg Field. Colorado’s Front Range juts up in the distance.

400,000 Niobrara Acres

The Niobrara is a far-flung formation, and many companies are building large acreage positions. One early mover in the play was Cirque Resources LP, a private, Denver-based independent.

Cirque Resources LP amassed 400,000 net acres in two different Niobrara play areas, says Peter Dea, president and chief executive.

Peter Dea, president and chief executive, has been focused on buying leases in the Niobrara and other oil-prone shales for some time. When Cirque was formed three years ago, shale-gas exploration in the Midcontinent and North Texas was de rigueur for the industry. Dea took a contrarian approach, and decided to focus Cirque on oil exploration in the Rockies.

The Niobrara was only one of a host of candidates, including the Bakken, Heath, Manning Canyon, Mowry and Gothic, that Cirque evaluated. The Niobrara made the cut: it offered company-building potential, was largely unleased, and held the promise of moveable oil that might be released with current technology.

“The Niobrara was an easy sell for me, because I had worked it in the late 1980s and early 1990s,” says Dea. Back then, a small frenzy of activity centered on industry success at Silo Field and in the Sand Wash Basin. Interest in the Niobrara waned after it became apparent that the early horizontal drilling technology could not deliver economic wells outside of small, highly fractured sweet spots.

This time around, the Niobrara looked much better. For Cirque, the game-changer was the industry’s new-found ability to hydraulically fracture laterals in multiple stages. “We are optimistic that this technology will allow the Niobrara to become a significant oil-resource play,” says Dea.

The company is pursing a “small crack” approach to the Niobrara, focusing on areas that are tectonically quiet. “We are trying to stay away from faults and major fracture systems, and we use 3-D seismic defensively to keep us out of those areas,” he notes.

Cirque has amassed 400,000 net acres in two different play areas. It assembled 250,000 acres in the northern DJ Basin, today right in the middle of the action. “We essentially had no competition, except for a bit around the edges of our play,” says Dea.

Cirque brought in Noble Energy as a 55% partner on that block; operations are split between the two companies. The partnership will see a few wells drilled this summer and early fall, to be operated by Noble.

The other Niobrara project comprises 150,000 acres in an undisclosed location. Cirque has brought a partner into this position as well. “We will have some activity on this block shortly, which we will operate,” says Dea.

“Our first phase of risk management is doing as thorough a job on the geology up front as we can. We try to select what we think are the most prospective areas and fairways,” he says.

Now it’s time for drilling, and activity looks promising. By the close of 2010, between 12 and 18 rigs look to be running from Wattenberg through southeast Wyoming in the Niobrara play. “There are so many active players that we will have a lot of help getting the Niobrara evaluated,” says Dea.

“By year-end, we will all be a lot smarter about the Niobrara than we are now.”

Goshen County Deal

Interest in the Niobrara is broad-based: in May, a sale of state lands in Wyoming saw 46 parcels in Goshen County go for an average price of $2,000 an acre.

That was good news for Australian explorer Samson Oil & Gas Ltd., which had a large block in Goshen County that it was looking to sell down.

Samson had been keen on the Niobrara for several years. The firm entered the U.S. in late 2004, and in 2006 Samson acquired a half interest in 100,000 acres in Goshen County, Wyoming, north of Silo Field.

The leases were targeted because they resided on the Goshen Hole Uplift, a post-Niobrara tectonic feature laced with abundant fractures. “The uplift occurred through Tertiary time,” says David Ninke, vice president, exploration. “Fractures and faults were active during the uplift.”

Samson drilled two wells on the Hawk Springs project: a vertical pilot hole, the #1 London Flats, and a horizontal well, the #1-29H London Flats. The latter test was drilled in 2006 to 9,173 feet measured depth, with a 2,400-foot lateral. Good shows were recorded during drilling, and Samson ran about 1,000 feet of liner in the lateral, but the well was not economic.

Still, it was early days in the understanding of shale resource plays, and technologies used today are much different.

As industry engagement with the Niobrara grew, Samson saw the opportunity to monetize some of its position and bring in an operator to push along evaluation. It wanted to reenter the #1-29H wellbore to test the Niobrara with current completion techniques, for an estimated cost of $1 million. “We think reentry of the existing wellbore is an inexpensive way to test our concept,” says Ninke.

Terry Barr, managing director, Samson Oil & Gas Ltd., says the firm had strong industry interest in acreage it recently offered for sale in Goshen County, Wyoming.

The company’s acreage tender offered a portion of its 40,800-net-acre holdings. “Major players in the shale industry showed interest,” says Terry Barr, managing director. “We wanted to sell off about 50% of our equity interest.”

In late June, the company reached an agreement with a large independent to sell 24,166 acres of its Niobrara position for between $61- and $79 million in cash. The final price depends on several triggers, including Samson’s ability to permit a new well location and also form a federal exploratory unit.

Samson will retain 16,300 net acres, and also gain an override on the leases sold. Closing was scheduled for late July.

“We have all the elements that we believe are necessary for success in the Niobrara,” says Ninke. “On our leases, the Niobrara has high TOC, it’s in the oil window, we have evidence of natural fracturing, and we have good thickness. It’s essentially a new play in our backyard.”

And now, Samson has a new operator in the neighborhood eager to investigate the Niobrara further.

Two-Basin Approach

Frac sand flows into a blender during a Halliburton stimulation of one of Noble Energy’s vertical Codell/Niobrara wells in Weld County.

Not all Niobrara activity is in the DJ Basin. In fact, operators have fanned out across Colorado and Wyoming to investigate the formation’s potential in diverse areas.

Private firm Laramie Energy II LLC is working the Niobrara in two locations, North Park Basin in Colorado and the Laramie Basin in Wyoming. The firm, formed in 2007 just after the first Laramie Energy was sold, focuses on the Rocky Mountain region. In addition to the Niobrara, Laramie II has efforts in other resource plays in the region, including the Williams Fork in the Piceance Basin.

“The Niobrara is a play that takes elements of patience and continued efforts,” says Bob Boswell, chairman and chief executive officer. “There are many factors: determining what area has the right attributes to be successful, determining the orientation of laterals, determining the best completion strategy.”

Laramie began to look at the Niobrara in 2008, led by thinking from geoscientist Jack Weiner. The company built positions and drilled two pilots. “Our two areas have different geological settings,” says Boswell. “One is heavily fractured and the other is not.”

Laramie Energy II LLC has work planned on both its Niobrara projects in Colorado’s North Park and Wyoming’s Laramie basins this summer, says Bob Boswell, chairman and chief executive office.

In the North Park Basin, the company accumulated some 10,000 net acres. EOG Resources brought initial attention to the Niobrara in North Park; beginning in late 2007 it drilled a number of horizontal wells into the shale.

Laramie’s vertical pilot well, the #18-15 Fuqua, was drilled to 8,000 feet in a highly faulted and fractured area in Jackson County in late 2008. The operator completed the well openhole, but after a few days of testing oil and gas it ran into borehole stability issues.

Next, Laramie plans to either drill a lateral from the vertical wellbore or put a pumping unit on the hole and begin production. “We envision moving forward on this project this summer,” says Boswell.

The company’s second project comprises 100,000 gross acres in the Laramie Basin. The firm liked this area because the Niobrara exhibited the right characteristics and the basin was only lightly explored.

In late 2009, Laramie drilled a vertical pilot well, #1-10 Dunmire Ranch, in Albany County, to 7,700 feet and ran a slotted liner. Rock evaluation data has confirmed that the Niobrara in the Laramie Basin is rich in organics and thermally mature. Petrographic analyses indicate that small-scale expulsion fractures are likely present in the Niobrara. Larger-scale natural fractures are lacking, so permeability will need to be artificially induced.

“Our plan is to do a light frac on the vertical well and observe its performance,” says Boswell. The company is also acquiring additional seismic to nail down stress directions.

Following treatment of the existing vertical well and seismic evaluation, Laramie plans a horizontal test. “We are looking at drilling our first horizontal in the southern portion of our acreage block,” he says. “We have a large position and we want to learn as much about it as we can with our initial wells.”

The company’s Wyoming acreage is a combination of both federal and state land. Currently it awaits the issuance of federal leases in the play that it bid on and won some 18 months ago. “We don’t include this acreage in our figures, because we still don’t have the leases,” says Boswell. “We are still waiting.”

Once its summer work program wraps up, Laramie plans to evaluate results to determine its next moves. “The Niobrara has the potential to be an excellent reservoir when properly drilled and completed,” says Boswell. “We think it could be a very significant source of oil for the country in the future.”

Certain aspects of the Niobrara play are very attractive, says Irene Haas, managing director, Canaccord Genuity. “But we don’t fully understand the pitfalls. It’s still so new.” Right, prairie flowers bloom (along with Niobrara drilling) in Weld County.

Dollars and Sense

The horizontal Niobrara is a potentially large but unrealized oily resource, in the opinion of Canaccord Genuity analysts. “Right now, we have less than 10 well data points that are publicly available,” says Irene Haas, managing director. “In contrast, more than 50 horizontal drilling permits have been approved in the DJ Basin. Information on the horizontal Niobrara play is going to explode; we’ll learn a lot more about this trend in the next 12 months.”

Certain aspects of the play are very attractive, says Haas. “But we don’t fully understand the pitfalls. It’s still so new.” A crucial point, one made by most of the operators as well, is whether the play is productive in a number of discrete “sweet spots,” or whether the horizontal Niobrara is continuous and economic across a large area. “This is what everyone is trying to figure out,” she says.

“Another big question is the importance of natural fractures, faults and joint systems—whether you want to drill in structured areas or stay away.”

In addition, the Niobrara is just one of many productive zones in the DJ Basin. Older units such as the Carlile shale and the Greenhorn limestone could be interesting bonus plays and could have a compounding impact in recoverable resource, she notes. A number of operators have made oblique references to early work in these zones, each of which has demonstrable potential.

Canaccord Genuity’s best-case preliminary assessment for the horizontal Niobrara, assuming that the play is continuous, is 4- to 6 billion barrels of recoverable oil, unrisked. Preliminary economics look good. Assuming per-well capital costs of $3.5 million, an initial daily production rate of 450 BOE, gross estimated ultimate recovery of 400,000 BOE, and Nymex prices of $80 a barrel for oil and $5.25 per thousand cubic feet for gas, the average horizontal well can generate an after-tax PV-10 of $3.1 million.

“Our best case yields an internal rate of return of 66%,” says Haas.

In general, the Niobrara appears to share many traits with its Cretaceous cousins, the Eagle Ford and Austin Chalk, in rock type, drill time, drill depths and ease of drilling. Early completion schemes are similar, she says.

One big difference between the Niobrara and the Eagle Ford-Austin Chalk system is the tectonic complexity of the former.

“The Niobrara chalk is likely to have a different twist,” she says. “Post-deposition structural imprints will likely add another level of intrigue to the play.”

And, truth be told, the Rockies have never been an easy place to prospect. But, the Niobrara’s strong showing to date has certainly enlivened this slice of the Patch.