ShaleTech: U.S. Rockies

In a sign of better times, a Newfield Exploration rig makes hole in Utah’s Uinta basin during 2014. The independent has suspended all drilling activity in the Uinta this year. Courtesy of Newfield Exploration Co.

Aside from the mosaic Niobrara shale, the fledgling unconventional plays within the U.S. Rockies are largely footnotes when stacked against the more fêted plays in Texas, North Dakota and elsewhere. As such, they find themselves lost in the shuffle, as precious capital shifts to their more-established counterparts.

With cash-starved independents opting for the higher returns of more developed plays, emerging unconventional prospects across much of Colorado, Wyoming and Utah find themselves out of vogue, for the time being at least, as planned 2015 activity has either been slashed appreciably or suspended altogether. EOG Resources, for one, says its 2015 emphasis on returns over growth will see it drill the minimum wells required to hold leases within its acreage in the Denver-Julesburg (DJ) and Powder River basins, with nearly all those wells to be left uncompleted until prices recover. “We do not believe that growing oil in what could turn out to be a short-cycle low price environment is the right thing to do,” Chairman and CEO Bill Thomas said in announcing fourth-quarter earnings and EOG’s 2015 guidance.

Meanwhile, compounding plummeting commodity prices and scattered takeaway issues, players across the Rockies also must deal with a stubborn anti-fracing groundswell, especially in Colorado. Having been thwarted repeatedly by the court system, Colorado fracing opponents this year began piggybacking the propaganda campaign that New Yorkers employed, which led to a wholesale ban in the state. The backlash, however, is not centered strictly in Colorado, as much of the Rockies is under the control of the U.S. Bureau of Land Management (BLM), which is being pressured continually to tighten drilling and fracing restrictions. In December, Democratic U.S. Representatives Mark Pocan (Wis.) and Jan Schakowsky (Ill.) went so far as to introduce a bill to ban fracing on all publicly owned lands—a proposal unlikely to gain traction, given the current Republican-controlled Congress.

“The State of Colorado obviously has been a challenge the last year,” Bart Brookman, president and CEO of PDC Energy, told analysts on Feb. 19. “I would say we have much calmer waters right now than we did a year ago. The industry continues to be out trying to educate the public about the benefits of the industry, (and) the safety aspects of the industry. We don’t feel any severe pressure on our capital programs or anything like that. But, the company continues to work with the other operators in trying to really promote this industry in the state of Colorado, and also be very involved on the political end. It’s a challenge, and it’s something we expect to continue in the future.”

NIOBRARA ENDURES

In Colorado, much of the fracing vitriol falls squarely on the Niobrara shale, which, owing to its location and stacked horizons, is known variously as the DJ-Niobrara, the Mancos-Niobrara or, more commonly, the Niobrara-Codell in recognition of the underlying sandstone that is the primary pay zone for some of the DJ basin’s most prolific wells. Regardless of the nomenclature used, if the Niobrara can be considered the regional barometer, and Weld County, Colo., home of the mature and prodigious Wattenberg field, its epicenter, the sledding will, indeed, be rough in the Rockies this year. Even this comparatively established play, which underlies most of Colorado and reaches into Wyoming, is suffering the brunt of drilling funds being earmarked elsewhere.

Fig. 1. Forecast Niobrara oil and gas production for March. Source: U.S. Energy Information Administration. Click image to enlarge.

“Weld County is likely to suffer the worst in the state. Denver may also face some downside risk, as it serves as a hub for the energy business in the surrounding state,” Mark Vitner, a senior economist with Wells Fargo Securities, told the Denver Post on Feb. 4. “It is way too soon to expect prices to have bottomed. We haven’t seen the kind of carnage you would expect to see in a market that has been oversupplied.”

Given the volatility of today’s onshore environment, the rig count, today, offers an imprecise forecast of tomorrow’s activity. That said, as of the week of Feb. 20, Baker Hughes data show 39 active rigs in the Niobrara, down three from the week prior, and 15 fewer than the 54 drilling at the same time in 2014. Three of those active rigs were targeting the Niobrara across the border in Wyoming, unchanged from the week prior. Furthermore, in the recently completed fourth quarter, operators drilled 61 new wells in the Niobrara, up from 50 wells drilled in the same quarter of 2013.

Fig. 2. One of the 13 Anadarko rigs that, for the time being, is drilling ahead in the Wattenberg field. Courtesy of Anadarko Petroleum Co.

The lower rig count notwithstanding, the U.S. Energy Information Administration (EIA) sees February-to-March oil production rising slightly to around 400,000 bpd, while the gassier windows are expected to deliver a month-to-month increase of 23 MMcfd, Fig.1.

The overall rig count could take another dip in early March, when Anadarko Petroleum, one of the most active players in the Wattenberg field, releases its long-awaited 2015 guidance. While not yet offering specifics, The Woodlands, Texas, independent said it plans a considerable reduction from the $9.26 billion in 2014 capital expenditures. Like many operators, Anadarko has delayed announcing capital distribution and activity plans for this year, as it continues to gauge the potential near-term market conditions.

In the fourth quarter, Anadarko said its flagship, 350,000-net-acre Wattenberg leasehold averaged 195,000 boed, a 78,000 boed increase over the like period of 2013. Anadarko averaged 13 rigs and drilled 104 wells, mostly all in its Wattenberg core, Fig. 2.

“Wattenberg’s exceptional performance was facilitated by the growing up of our acreage positions, outstanding reservoir performance, improved efficiencies, enhanced drilling and completions and, importantly, the investments we made in key infrastructure expansions,” CEO Al Walker told analysts during the fourth-quarter earnings conference call.

Fig. 3. An Encana rig, with sound barrier, drilling on the independent’s 49,000 acres in the DJ basin. Courtesy of Encana Corp.

There is no such uncertainty with Encana, which says 80% of its reduced capital budget this year will be funneled into its Montney, Duvernay, Permian and Eagle Ford holdings, where a spokesman said the Canadian operator has its highest returns. As of late February, Encana planned to spend between $200 million and $300 million in the 49,000 net acres that it holds in the DJ basin, where tentative plans call for running three to four rigs and drilling 30 to 35 net wells, Fig. 3. However, those numbers are likely to be revised downward with the release of final year-end results at the end of February, the spokesman said. “This will include further reductions in spending in the DJ, as well as the San Juan basin and the Tuscaloosa Marine shale,” he said.

Encana averaged six rigs last year and recorded a production mix averaging 11,000–12,000 bpd of oil and condensate; 5,000–5,000 bpd of NGLs and 50–60 MMcfgd.

Encana says one of the early casualties of the free-fall in prices was plans to develop centralized production centers outside populated areas along the Front Range, which has been the hotbed of fracing opposition. The first hub was originally scheduled to be up and running early this year, but it has been delayed. “The drop in prices, and a lower level of activity in the DJ, means construction of the hub has slowed as well,” the spokesman said. “It is still
under construction.”

The Wattenberg’s premier leaseholder, Noble Energy Inc., said it will cut its year-over-year drilling activity from nine to four rigs, focusing primarily on its core 61,000-acre Wells Ranch and 44,000-acre East Pony areas, where a combined, 20 plug-and-perf-completed wells were put online in the fourth quarter. One the heels of a 40% spending reduction this year, the Houston independent said it has earmarked $1.8 billion to be split evenly between its 610,000-net-acre position in the DJ basin and its Marcellus leasehold.

Noble averaged record DJ production of 108,000 boed in the fourth quarter, up 5% from the previous quarter. Of that, a quarterly-record 82,000 boed flowed from its horizontal wells, an 11% jump from third-quarter 2014. A total of 80 wells was drilled during the fourth quarter, Noble said, including 28 laterals with an average extended reach of 6,000 ft, compared to the typical 5,555-ft horizontals drilled last year. 

“Production from the DJ basin represents over a third of our total company volumes,” said President and CEO David Stover. “With a focus on continuous improvement through integrated development planning, and enhancements in drilling and completion procedures, we are accelerating long-term growth plans in the DJ basin.”

Included within those growth projections is the ongoing development of the centralized integrated development plans (IDP) that Noble unveiled last year, which it says will not only increase net present value (NPT), but reduce the environmental footprint throughout the life of the asset. Noble eventually plans to install five IDP complexes within its Wattenberg Wells Ranch and East Pony developments, where various downspacing scenarios and completion types will be evaluated.

Gary Willingham, senior V.P., U.S. Onshore Region, said two of the so-called underground laboratories have already been installed on Wells Ranch, with incorporated fiber optics monitoring offering valuable insight for optimizing completions. “Those underground laboratories are designed to gather data strategy throughout the lateral length of the wells those fiber optics are in,” he said. “And (for) the wells that we ran the fiber optics in, we’ve actually done different completion technique tests along that lateral.”

“We may do three stages using one technique, the next three using another technique, and so on, and with those having fiber optics downhole, we can actually determine the performance difference between each of those techniques, which allows us to further optimize as we go.” 

Denver-based PDC Energy, meanwhile, will keep its drilling dollars at home, saying nearly all of its reduced capital budget this year will be allocated to its Wattenberg assets. The independent cut 2015 spending by $84 million, from $557 million in 2014 to $473 million, but says 92% will be earmarked to the Wattenberg. “We are seeing the capital structure on our drilling programs improve dramatically, resulting in ongoing value-added drilling, particularly in the Wattenberg field,” Brookman said.

PDC plans to continue a five-rig program this year, targeting both the Niobrara and Codell within its 97,000-net-acre leasehold, which in 2014 delivered 9.3 MMboed. PDC drilled 116 wells in the Wattenberg last year and plans to spud 119 wells in 2015, with up to 65% of those targeting the Niobrara and the remainder directed to the Codell.

Fig. 4. Most of Wyoming’s horizontal oil drilling activity is centered in the Powder River basin, in Campbell and Converse counties. Source: U.S. Energy Information Administration. Click image to enlarge.

“Our technical testing continues to pay dividends in the overall performance of this drilling program,” said senior V.P. of Operations Scott Reasoner. “Our first 20-well equivalent project, Sunmarke, is online with limited data, but early results are positive. We’ve drilled and completed four Niobrara and four Codell wells on this half-section with 32-acre spacing.”

WYOMING AT A CROSSROADS

A comparative newcomer to the unconventional scene, much of the activity in Wyoming, of late, has centered on the 43,000-sq-mi Powder River basin, where production historically has flowed from the higher-permeability Turner, Parkman, Shannon, Sussex and Frontier formations. Over the past few years, the state has seen an acceleration in horizontal activity, particularly in Converse and Campbell counties (Fig. 4), where, as with the Wyoming swath of the DJ basin, operators target the Niobrara-Codell shale which, together or singularly, has contributed heavily to continual year-over-year production increases.

Statewide, 35 rigs were at work during the week of Feb. 20, down four units from the previous week, and 16 fewer than the 51 active rigs recorded during the same period of 2014. According to data from the Wyoming Oil and Gas Conservation Commission (OGCC), Niobrara-Codell wells in Converse and Campbell counties during 2014 delivered a cumulative 3,913,539 bbl of oil, up from 2,687,7389 bbl the year prior. Conversely, Niobrara-Codell gas production in the two counties, likewise, was up significantly last year to 21,282,989 Mcf from 12,028,156 Mcf in 2013.

Less than a year ago, EOG Resources announced that it had transitioned four new horizontal plays in the Powder River, and the Wyoming sector of the DJ basin, from the evaluation phase and into its “high rate-of-return drilling portfolio, alongside the successful South Texas Eagle Ford, North Dakota Bakken and Delaware basin Leonard assets.” Flash forward 10 months, and EOG has put the brakes on any meaningful development of its Rockies assets until prices recover. “Our activity in 2015, in the DJ basin, will be limited, drilling wells needed to maintain leaseholds and finishing completion operations on a few remaining wells drilled last year,” said Billy Helms, executive V.P., Exploration and Production.

EOG said it closed out 2014 completing “several excellent wells in these emerging plays.” The Houston independent primarily targets the Codell formation in Laramie County, where it holds 72,000 net acres. To the north, in the Powder River basin, EOG holds 63,000 net acres in Converse and Campbell counties, prospective for the Turner formation, and another 30,000 acres targeting the Parkman.

Two of the most recent DJ Codell wells delivered average initial oil production (IP) rates of just under 1,423 bpd, in addition to around 128 bpd of NGLs and 445 Mcfgd, on average. To the north, the three latest Parkman horizontal wells completed in the Powder River basin delivered IPs averaging 1,263 bopd and roughly 667 Mcfgd, while the two most recent Turner completions averaged 920 bopd and 1.9 MMcfgd.

“In the DJ basin, EOG made significant progress in both the Codell and Niobrara,” Helms said. “We’ve been experimenting with wellbore targeting, inter-well spacing and modifications to the completion design for both intervals. For the Codell, we’ve identified a specific stratographic interval within the pay section that, when targeted rightly, enhances the performance of the well.

“The Powder River basin is a stacked pay system, and we’ve drilled primarily in apartment and tunnel oil reservoirs, similar to other areas within EOG’s portfolio. In 2014, we focused on well targeting and completion designs, and inter-well spacing, to determine the optimal development plan.” Overall, EOG expects to complete approximately 45% fewer wells this year than it did in 2014.

Fig. 5. Major structural features and igneous intrusions in the Uinta-Piceance province. Source: U.S. Geological Survey. Click image to enlarge.

With an estimated 20% reduction in its 2015 E&P budget, Devon Energy plans to operate two rigs within its 150,000-net-acre Powder River basin leasehold, where it focuses primarily on stacked oil targets in the Parkman fairway. Devon, which ran four rigs in the fourth quarter, says its 2015 Powder River well designs will feature 9,600-ft laterals, more than twice the length of its earlier wells.

Net production averaged 19,000 boed in the fourth quarter, a 9% year-over-year increase. Devon says it will spend approximately $350 million this year, primarily drilling Parkman development wells.

Anadarko Petroleum holds more than 100,000 mineral-interest acres in Laramie County, where, by the end of 2014, it had participated in 70 wells, testing both the Niobrara and Codell. Anadarko’s emerging Powder River basin assets produced 37,000 boed in the fourth quarter, down from 41,000 boed in fourth-quarter 2013. At year’s end, Anadarko had no rigs running in the play.

Elsewhere, with the late September acquisition of the Pinedale holdings of Shell Western E&P Inc. (SWEP), Houston’s Ultra Petroleum Corp. now controls 49,000 net acres in it and the neighboring Jonah tight gas field. As of late February, Ultra still planned to operate four rigs in the twin plays this year, with an average well cost of $3.5 million.

PICEANCE, UINTA SPUTTER

Activity in the primarily gassy Pi-ceance basin of northwestern Colorado and the neighboring Uinta basin of Utah (Fig. 5) is especially hard-hit, as major players announce significant cutbacks, with at least one planning to curtail 2015 drilling altogether.

Fig. 7. A pumpjack at work on a Newfield Exploration location in the Uinta basin. Courtesy of Uinta Exploration Co.

WPX Energy, one of the most active gas producers on the Western Slope, says its capital expenditures this year will be half of what it spent in 2014. The Tulsa, Okla.-based independent said it will lay down six rigs in the Piceance basin this year, cutting its fleet from nine to three active units. WPX plans to spend between $200 million and $225 million in the Piceance, and will forgo completions on about 20 newly drilled wells.

“Head winds bring challenges and opportunities,” said President and CEO Rick Muncrief. “We’re ready for both. It’s why we have a long-term plan to reshape WPX and grow our margins and cash flow. Margin expansion comes from diversifying our production and right-sizing our cost structure.”

WPX said its Piceance holdings include its 35,000-net-acre Ryan Gulch field in the upper elevations of western Colorado and 180,000 net acres prospective for the Niobrara and the overlying Mancos shale. During third-quarter 2014, WPX completed two new Niobrara delineation wells in the Piceance, including a parachute horizontal test well that produced at a peak rate of 14 MMcfed, while a vertical test is delivering 2 MMcfd from the Mancos, Fig. 6. The Niobrara discovery well produced more than 2.7 Bcf of cumulative gas production in just over 18 months, the company said.

Elsewhere, across the border, 11 rigs were making hole in Utah as of Feb. 20, one less than the previous week, but off 15 from the same reporting period of 2014. That tally is expected to drop further, as Newfield Exploration, one of the predominant players in the Uinta basin, says it will forgo all drilling this year and divert those dollars to its Oklahoma assets.

Newfield holds 225,000 net acres in the Uinta Central basin, approximately 1,000 acres of which is under federal control, and last year averaged five rigs in the basin, which The Woodlands, Texas, independent describes as its largest asset in the Rockies, Fig.7.

Fig. 6. The deep resource assessment of the WPX Ryan Gulch play is testing the Mancos and underlying Niobrara shale. Source: WPX Energy Inc. Click image to enlarge.

“We will not be running any rigs in the Uinta basin in 2015, with oil at its current prices,” a spokesperson said. “The lower oil prices have affected our returns and margins in each of our play areas. In the Uinta basin, our revenue is impacted by a large oil price differential and lease operating expenses. So, because of this, we have shifted much of our capital and rigs to our highest-return areas and plays, which are mainly in Oklahoma.”

Notably, Newfield last summer was given “split estate” authorization by the U.S. Department of the Interior (DOI), which cleared the way for drilling four directional wells into federal leases from two existing pads on private surface rights. The spokesperson said all four of the SXL-designated wells were tested successfully, with the three Uteland Butte SXL wells averaging 90-day production of 1,067 boed, while the Wastatch SXL on the second pad delivered sustained 90-day production of 1,241 boed.

Ultra Petroleum, which entered the Uinta in October 2013 with a $650-million acquisition of 8,200 acres in northeastern Utah, was running one rig in late January and drilling four to five wells per month. Owing to declining prices, the operator has since suspended all completions. “As a result of the decision to defer completions, our current Utah capital budget for 2015 includes the capital to drill, but not complete, wells through the term of our rig contract that is set to expire at the end of April,” said senior V.P. of Operations C. Bradley Johnson. “ Meanwhile, we are pursuing cost reductions, monitoring oil prices and tightening basis differentials and maintaining flexibility for capital deployment in Utah.”

Meanwhile, QEP Resources, which holds 250,000 net acres in the Uinta, has not disclosed any plans for 2015. QEP, which employs both vertical wells and multi-stage horizontals, and which primarily targets gas and NGLs in the Mesaverde formation, said its lateral wells in 2014 produced at average rates of 9 MMcfed.  

About the Authors

Jim Redden

Contributing Editor

Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.