The heart of the Denver-Julesburg (D-J) Basin is still beating.

D-J operators have remained active despite the low commodity price environment. Companies have trimmed operation costs and improved drilling efficiencies amid a backdrop of political and A&D activity. The overturn of fracking bans in two Colorado cities, May 12 fracking protests and a $505 million acquisition in the Wattenberg Field are among the standouts.

A recent study suggests E&P perseverance is about to pay off.

According to a study by Rystad Energy on May 23, the basin’s “core of the core”—Weld County, Colo.—exhibits the most commercial fracklog in the U.S. with completion costs averaging $4.70 per barrel. Weld also has one of the largest inventories of drilled but uncompleted wells (DUC) in the U.S., with almost 600 oil wells awaiting completion crews.

Rystad Energy, DUC, Weld County, Colorado, D J Basin, horizontal, fracking, shale, Niobrara

“This implies that the major part of the U.S. shale DUC inventory is commercial in the current oil price environment, and significant support to the U.S. Lower 48 oil supply can be expected in the near months as market sentiment gradually moves in a positive direction,” said Rystad’s study analyzing the commerciality of well completions.

A large inventory of DUCs has been driven up by intentional completion delays initiated by Anadarko Petroleum Corp. (NYSE: APC), according to Rystad. Anadarko operates nearly half of Weld’s fracklog. Meanwhile, PDC Energy Inc. (NASDAQ: PDCE), Noble Energy Inc. (NYSE: NBL) and Whiting Petroleum Corp. (NYSE: WLL) hold roughly 10% of the fracklog each.

For the Rockies, Jessica Pair, upstream manager for Stratas Advisors, estimates the DUC breakeven price is about $30 per barrel of West Texas Intermediate crude. But that figure is centered more on the prime producing locations.

“Currently in the D-J, in Weld County specifically, that is considered the core of the core and the main operators that are focused there,” Pair told Hart Energy. Operators “are still deploying a lot of capital to that region and they’re still pretty active in the play.”

One of the largest operators in the D-J, Noble, has cut well costs in the region by more than 35%, reducing extended-reach lateral wells to $2.4 million. The company said it will continue to shift its well designs to focus on extended-reach laterals with monobore drilling, slickwater completion fluid and enhanced proppant loading.

Across the basin, improvements and efficiencies have risen as prices rolled down—for both drilling and completion, said Jack Wiener, Halliburton’s chief technical adviser.

“When I first started doing this, about five years ago, we were drilling a 5,000-foot Niobrara well in 12 days, something like that,” Wiener said during the recent DUG Rockies conference in Denver. “We are now with rotary steerables, monobores and good well design and well planning, earth modelling—we’re down to 2.75 days at a casing to TD (total depth). That is impressive and I just see continued improvements and getting better.”

Lateral Thinking

As with operators in every play, finding savings during this commodity price downturn has become as important, and linked to profitability, as innovation. A slew of companies have managed to cut opex in the Rockies.

In the D-J Basin, Anadarko Petroleum brought down its well costs by 11% to $2.4 million during the quarter from $2.7 million at year-end 2015. The reduction primarily due rested on a 10% drop in completion costs, the company said.

Niobrara, shale, production, rises, despite, falling, rig count, EIA

In February, PDC Energy said its well costs have decreased by about 10% in the Wattenberg. Savings range from $2.6 million for standard-, $3.6 million for mid- and $4.6 million for extended-reach lateral wells. The company estimates this will result in $40 million of savings to its current capital plan.

Bill Barrett Corp. (NYSE: BBG) also reduced the cost of its D-J wells by 42% since fourth-quarter 2014, with extended-reach lateral completed well costs averaging $4.75 million in January.

Similarly, Whiting Petroleum has reduced its drilling costs in the D-J Basin through a new wellbore design that has slashed drilling days in half.

At Colorado's Redtail Field in Weld County, Whiting targets the Niobrara A, B, C and Codell/Fort Hays formations. The company has implemented a new wellbore configuration which eliminates the need for an intermediate casing string by cementing 5.5-inch casing from surface to total depth.

The method reduced Whiting's drilling time for a 7,000-foot lateral in the D-J to an average of 4.44 days during the first quarter. The company's record drilling time stands at 2.79 days.

Like Whiting, Noble has also shaved off drilling time in the D-J Basin.

The company averaged drilling times during the first quarter in the D-J for a standard lateral length well (4,500 feet) that were fewer than six days, while medium (6,000 feet) laterals are drilled in an average seven days and long (9,000 feet) in eight days. A long lateral well was drilled, spud to release, in a record of fewer than six days.

E&P Roundup

As commodity prices nosedived, so has E&P spending.

Global upstream capital spending fell by more than 25% in 2015 with further double digit declines expected during the next two years, said John England, vice chairman and U.S. and Americas oil and gas leader for Deloitte, at the recent MergerMarket Energy Forum in Houston.

Noble Energy

For 2016, Noble has slashed its capex by about half at $1.5 billion, with $600 million earmarked for the D-J.

On average, Noble plans to operate two horizontal rigs in the D-J during 2016. The company anticipates drilling about 115 wells to total depth, 80% of which are planned in the D-J.

During the first quarter, Noble drilled 24 wells at an average lateral length of more than 7,300 feet. About 60% of the wells spud were extended-reach lateral wells. On a per lateral foot basis, well productivity is up year-over-year by more than 30% in the D-J, the company said.

Noble commenced production on 36 wells (equivalent to 43 standard lateral length wells) during the first quarter. The company said IP rates from enhanced completion designs (slickwater with higher proppant concentrations) continue outperform legacy completions.

For the 22 wells that achieved 30 days of production in the quarter:

  • IP rates averaged 836 barrels of oil equivalent per day (boe/d);
  • Average lateral length was 5,860 feet; and
  • More than half utilized proppant loading of at least 1,000 pounds per lateral foot.

Noble Energy exited the first quarter with 46 DUCs in the D-J Basin.

Anadarko Petroleum

Anadarko's 2016 capex is estimated at $2.8 billion, with $1.1 billion squared away for its U.S. onshore capital investments, which are primarily focused in the D-J and West Texas' Delaware Basin.

During the first quarter, Anadarko operated an average of two rigs in the D-J and drilled 26 wells, a drop of 49 wells from the prior quarter. In total, the company completed 46 wells in the basin during the quarter.

Elsewhere in the Rockies during the first quarter, Anadarko drilled three operated wells in Utah's Greater Natural Buttes and two carried-exploratory wells in its Wyoming exploratory area.

Anadarko's Rockies assets delivered sales volumes averaging 355,000 boe/d during the first quarter, a 6% increase from fourth-quarter 2015. Oil volumes were held nearly flat from the previous quarter.

The company's Wattenberg field net sales volumes increased during the quarter by about 10,000 boe/d, or 4%, compared with fourth-quarter 2015. Year-over-year sales volumes were up by about 24,000 boe/d, or 11%.

PDC Energy

In 2016, PDC Energy lowered its capex to $425 million, down 26% from $575 million in 2015.

The company anticipates running four rigs in the Wattenberg through year-end based on commodity prices at the time of its first-quarter earnings call, PDC President and CEO Bart Brookman said according to a SeekingAlpha transcript.

Brookman said the company will continue to push a series of technical enhancements including longer laterals, completion modifications, monobore drilling and the evaluation of downspacing projects.

In the first quarter, PDC Energy turned-in-line 47 gross operated wells in the Wattenberg during the first quarter and produced 47,840 boe/d—a year-over-year increase of about 64%.

First-quarter production increased year-over-year by 58% to 4.6 MMboe, or 50,216 boe/d, primarily from its successful horizontal drilling program in the Wattenberg, the company said. The production growth was regardless of a 100 Mboe loss due to a severe snowstorm in late March.

Niobrara, shale, natural gas, production

The company expects to spud about 140 wells in 2016, five in the Utica Shale and 135 in the Wattenberg.

Whiting Petroleum

Whiting Petroleum plans to spend $500 million in 2016, running two rigs in the Niobrara and two more in the Bakken Shale. The company projects an inventory of 95 DUCs in the Niobrara by year-end 2016.

Production in the company’s Redtail Field averaged 11,840 boe/d during the first quarter.

Bill Barrett

Niobrara, shale, oil, production

At the midpoint, Bill Barrett projects $125 million in 2016 capex. Although its projected budget is 55% less capital than 2015, the company expects to sustain production at “levels similar” to last year, said Scot Woodall, Bill Barrett's CEO and president.

The company is virtually halting operations in the basin for now

So far 2016, Bill Barrett has pared down its portfolio, selling noncore Uinta Basin assets for $30 million in order to sharpen its focus in the D-J's Niobrara Shale.

Company 2016 production guidance ranges between 5.8 MMboe and6.2 MMboe with a mix of 65% oil, 20% natural gas and 15% NGL. About 65% of the company’s oil production in 2016 is hedged at $80.47 per barrel.

"Based on the uncertainty of an oil price recovery during 2016, we are making the decision to curtail drilling activity to preserve capital and will monitor industry conditions to determine the appropriate time to resume drilling. Accordingly, we recently released the sole rig we were operating" in the D-J, Woodall said in March.

Synergy Resources

Synergy Resources Corp.’s (NYSE: SYRG) 2016 capex is $140 million at the midpoint. The company will operated one rig and plans to drill 55 gross (52 net) wells.

Average daily production for 2016 is estimated at up to 12,000 boe/d. This compares to the average daily production of 8,750 boe/d for the 12-month period ended Aug. 31, 2015.

Synergy also entered an agreement with Noble Energy to acquire 33,100 net acres, mostly undeveloped, in Weld for $505 million. The divested acreage represents 8% of Noble’s D-J Basin acreage and 2% of its production.

Through the deal, Noble Energy adds half a billion dollars in liquidity. Concurrently, Synergy pieces together a contiguous acreage block in its Wattenberg fairway.

Synergy Chairman and CEO Lynn Peterson said he expects development of the company's newly-acquired properties in Weld County to be a "significant" part of its expanded 2017 operated program, which is expected to incorporate up to three rigs.

Emily Moser can be reached at emoser@hartenergy.com. Select charts and maps by Darren Barbee, dbarbee@hartenergy.com.