October 2019

Niobrara-Codell shale: Record production amidst regulatory mélange

Staff / World Oil

The operators remaining in the unconventional heart of the Denver-Julesburg (DJ) basin are taking Colorado’s newly convoluted regulatory structure in stride, with new highs in both oil and gas production.

Fig. 1. September-to-October oil and gas production is predicted to rise by 71,000 bpd and 229 MMcfd, respectively. Source: U.S. Energy Information Administration (EIA).
Fig. 1. September-to-October oil and gas production is predicted to rise by 71,000 bpd and 229 MMcfd, respectively. Source: U.S. Energy Information Administration (EIA).

Traversing Colorado and southeastern Wyoming, the triple-deck Niobrara and underlying Codell shales, separately or together, are expected to produce a play-record 767,000 bpd and 5,700 MMcfd of oil and gas, respectively, in October (Fig. 1), according to the latest guesstimate of the U.S. Energy Information Administration (EIA). In October 2018, EIA estimated oil production coming in at 620,000 bpd and gas at 5,177 MMcfd. Basin-wide gas production, long constrained by takeaway limitations and high line pressures, got a boost in August with the commissioning of DCP Midstream’s 200-MMcfd O’Connor deep-cut cryogenic plant. 

“The gas is going to debottleneck itself,” Noble Energy Inc. President and CEO Brent Smolik told analysts in an Aug. 2 earnings call. “I think, by the third and fourth quarter, we’ll see enough NGL capacity, where the constraints in the basin will get relieved.”

Fig. 2. Amid Colorado’s tangled regulatory structure, rural acreage remains at a premium. Image: HighPoint Resources Corp.
Fig. 2. Amid Colorado’s tangled regulatory structure, rural acreage remains at a premium. Image: HighPoint Resources Corp.

While production is up year-over-year, drilling activity slipped to a September average of 22 active rigs (Fig. 2), says Baker Hughes, compared to 27 rigs for the same month last year. Activity is largely concentrated in, and around, the 50-year-old Wattenberg field in Weld County, Colo., which is, at once, the state’s most industry-supportive county and also the bull’s-eye for anti-drilling activism.

Meanwhile, recent high-profile acquisitions by Occidental Petroleum Corp. and PDC Energy, Inc., have altered the Niobrara-Codell pecking order, as they and other operators sort through the new regulatory regime.


After the anti-oil community failed in a statewide vote last November to quintuple setbacks and essentially put most of Colorado’s prospective acreage off-limits to new wells, the state has since punted much of its regulatory authority to local governments. A law that took effect in April gives county and municipal governments the power to first approve or reject drilling plans within their boundaries before the state regulator considers a permit application. Along with tightening emission standards, the so-called SB-181 initiative also restructures the Colorado Oil and Gas Conservation Commission (COGCC), the state’s regulatory agency, most notably dropping from three to one the industry representatives on the commission.

The offshoot has been a veritable mélange of proposed regulations. Despite heated opposition from the heavily populated Front Range constituency, the government of Weld County, which accounts for nearly 90% of the state’s production, has adopted a more industry-friendly strategy. The one-of-a-kind Weld County Oil and Gas Energy Department began operations in August, which the county commissioners say “solidifies their commitment of preserving oil and gas production in the county.”

On the other extreme, Adams County, which surrounds Denver and is ranked as Colorado’s number-two producer, quickly jumped on the new law to propose a doubling of the setback to 1,000 ft and tighter emission and noise rules—measures that overstep the intention of the new law, says Dan Haley, president and CEO of the Colorado Oil and Gas Association (COGA). According to COGCC data, Adams County had produced nearly 4.6 MMbbl of oil and 8,944,064 MCF of gas between January and August, compared to a total of just over 3.6 MMbbl and 7,780,412 MCF of gas for all of 2018.

“With the Senate Bill 181, the goal is to have operators get these sorts of local agreements in place first and before submitting their permits to the state, just to try to get the state out of being the mediator in-between the two parties,” says Matt Owens, president and acting CEO of Extraction Oil and Gas, Inc. “And, so now that we’ve got this agreement done, we’ll just go about the normal state permitting process and submit our permits to the state, just the normal way that we had in the past. Since we already have the local approvals, they should flow through the state at a reasonable pace.”

Owens was referring to the July 16 agreement with the City of Aurora, spanning both Adams and Arapahoe counties, for the pure play operator’s Hawkeye development on the eastern fringes of Denver. The agreement initially provides for five pads in the 66,000-net-acre development area and “solidifies Extraction’s ability to develop over 65 initial long-lateral locations and creates a pathway to develop our remaining acreage in the area,” Owens said.

The Aurora pact follows the September 2018 approval of a comprehensive drilling plan (CDP) for the Broomfield development just west of Denver. With drilling underway on the Broomfield Livingston pad, first production from the Interchange pad, featuring Extraction’s first 3-mi laterals, is expected near the end of the third quarter.

Extraction controls roughly 289,000 largely contiguous net acres, with 125 and 112 gross wells to be drilled and completed, respectively, this year with average lateral lengths of around 10,560 ft. The company expects to hook 111 gross wells up to production in 2019. Extraction will run one to two rigs and no less than one frac spread during the year, targeting the three Niobrara horizons and the Codell.


Noble Energy says a long-term planning and batch submission strategy is paying dividends, as it now holds more than 550 development authorizations, with the pending North Wells Ranch CDP application offering the potential for an additional 250 permits.

Meanwhile, Noble cites reduced cycle times, in tandem with row development and lower-fluid frac designs, for well cost reductions of $500,000 to $1 million/well. “Several of our 9,500-ft laterals in DJ were drilled in less than five days,” says Smolik. “The things that we’re doing that are most sustainable are on the completion side of the business, (where) we’ve been able to fairly significantly improve the pumping hours per day and the number of stages that we’re able to get done per day.”

Fig. 3. A production pad within Noble’s 342,000-net-acre DJ leasehold. Image: Noble Energy Inc.
Fig. 3. A production pad within Noble’s 342,000-net-acre DJ leasehold. Image: Noble Energy Inc.

In the second quarter, the two rigs operated by the Houston-based independent drilled 26 wells, with average laterals of 10,051 ft . The company, which controls 342,000 net acres in the DJ basin, also completed 33 wells and initiated first production on 36 wells, with 55% of quarterly activity focused on the Mustang asset in southern Weld County. Average second-quarter production of 145,000 boed was 20% higher year-over-year, Fig. 3.

Owing to its 65,000-net-acre position in the operator-friendly confines of unincorporated Weld County, Bonanza Creek Energy, Inc. has added no less than 26 drilling authorizations since SB-181 was signed into law. The company says its permit inventory is sufficient for well into the 2020 Niobrara-Codell drilling program.

For this year, Bonanza Creek will drill 38.6 net (59 gross) wells and put 32.8 net (45 gross) wells into production. Despite no new wells turned-in-line during the second quarter, production jumped 62% year-over-year to 24,400 boed from 15,077 boed delivered in the second quarter of 2018. The higher-than-expected production prompted the company to raise year-end guidance to a high of 24,000 boed.


HighPoint Resources Corp. is quick to point out the “favorable regulatory environment,” characterizing the entirely rural 151,400 net acres it controls across Colorado’s Northeast Wattenberg and southeastern Wyoming. The pure play operator’s largely contiguous leasehold includes 86,800 net acres in Hereford field near Laramie, Wyo., which delivered record second-quarter production of more than 10,000 boed.

During the quarter and into July, 50 gross wells were placed on flowback, with production, as of Aug. 8, exceeding 37,000 boed. Targeting stacked pay development of the Niobrara and Codell horizons, cumulative second-quarter production jumped 18% year-over-year to 2.84 MMboe, and HighPoint expects to exit 2019 with sales volume ranging from 12.5 MMboe to 13 MMboe.

The company drilled three gross Hereford wells during the quarter, with 23 gross wells, completed with average 9,500-ft lateral reaches, placed on flowback, as part of a sweeping reservoir and geologic technical study within two drilling spacing units (DSU). The study, which included microseismic monitoring and took in more than 1,860 aggregate completion stages, was orchestrated “to provide definitive conclusions, with respect to optimal well density and completion design.”

In the legacy Northeast Wattenberg asset, HighPoint drilled 12 gross wells and placed 10 gross wells on flowback during the quarter. Of those, seven extended-reach (9,500-ft) wells placed on flowback, on the western flank of the Wattenberg, tracked above the 1-MMboe type-curve after 30 days online. In a related development, Summit Midstream commissioned a new gas processing plant in July, increasing Hereford gas processing capacity from 20 MMcfd to 60 MMcfd.

Though Colorado is the Niobrara core, EOG Resources, Inc., is credited with igniting the play in 2009 with the Jake well in Wyoming. EOG now holds 88,000 net acres in the Wyoming portion of the DJ basin, where it has identified the Codell as a premium play.

EOG completed 12 net (18 gross) Codell wells in the second quarter, with average 11,400-ft lateral reaches, with six of the wells averaging 14,000 ft. The wells averaged 30-day initial production rates of around 900 boed. The company plans around 35 net Codell completions in the Wyoming DJ basin this year.

Chesapeake Energy Corp. recently drilled its first Niobrara well since 2014 in Wyoming’s Powder River basin (PRB), with initial results pending. Two additional Niobrara wells are on tap for later this year, as well as a test of the volatile oil window of the underlying Mowry formation. Chesapeake is operating six rigs across a 248,000-net-acre PRB leasehold.

In a related development, the regulatory Wyoming Oil and Gas Conservation Commission (WOGCC) in July advanced a rule change meant to resolve a long-simmering dispute over drilling permit backlogs. The rule change requires “first-to-file” operators to begin drilling within two years to retain control of a lease.


Meanwhile, Occidental’s bold acquisition of Anadarko Petroleum includes nearly 400,000 net acres in the Wattenberg core, which the latter had long described as the crown jewel of its U.S. onshore portfolio. The $55-billion deal closed on Aug. 8.

Occidental is keeping up the play-leading pace, averaging four rigs and three completion crews this year, with plans to drill and complete nearly 300 wells, according to a spokesperson. While no year-end production targets have been set, Anadarko closed out 2018 with record Wattenberg production averaging 272,000 boed.

PDC Energy was elevated in the DJ basin hierarchy in August, with the $1.7-billion all-stock acquisition of SRC Energy. The transaction expands PDC’s leasehold to 182,000 net contiguous acres in the Weld County core, with pro forma second-quarter production of 16,000 boed.

Prior to the merger announcement, PDC drilled 43 wells in the second quarter and put 27 wells on production, with most activity concentrated on the western side of the gassier Kersey asset. The company intends to continue running two rigs and one completion crew through the third quarter and into next year, as it whittles down a now-combined drilled-but-uncompleted (DUC) inventory that is expected to reach an estimated 220 wells by year-end 2019. By contrast, the latest EIA data show an aggregate 438 DUC wells throughout the Niobrara as of August.

“We’re going to catch up on DUCs (in 2020), and then probably late 2020 or sometime in the first half of 2021, we’ll most likely deploy a third rig in there,” said President and CEO Barton Brookman, some two weeks prior to the Aug. 26 merger announcement. 

About the Authors
World Oil
Related Articles
Connect with World Oil
Connect with World Oil, the upstream industry's most trusted source of forecast data, industry trends, and insights into operational and technological advances.