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| An Encana rig, on location within the operator’s 49,000-acre Niobrara-Codell leasehold (photo courtesy of Encana). |
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Resisting unrelenting community efforts to keep it in the cradle, the nascent Niobrara shale and its underlying siblings are doggedly evolving from vexing infants to productive adolescents.
To be sure, between oil production on pace for yet another record and steady reductions in well costs, it appears operators have tightened their collective grip on the notoriously tricky geology of the still-emerging play. It traverses most of the Denver-Julesburg (DJ) basin of the U.S. Rockies, extending across northeastern Colorado, southeastern Wyoming, and into northwestern Kansas and southwestern Nebraska. With drilling efficiencies on the fast track, much of the focus has turned to optimizing spacing, and fine-tuning completion and stimulation strategies to further optimize drainage from the naturally fractured and organic-rich pay zone. Or, more accurately, pay zones, as operators continue to take a look-see at no less than five horizons they see as providing prospective, stacked play potential, which, depending on the constitution of individual leases, effectively multiplies per-capita acreage positions, Fig. 1. Taking the aggregated pay zones into consideration, the actual, total, recoverable oil reserves for the triple-bench Niobrara petroleum system most definitely will far exceed the earlier 2-Bbbl assessment by the U.S. Energy Information Administration (EIA).
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| Fig. 1. Operators are targeting the stacked play potential of the horizons underlying the Niobrara-Codell shale (image courtesy of PDC Energy Inc.). |
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“The one thing we don’t have to worry about in the Niobrara is oil-in-place. There is a tremendous amount of oil-in-place,” said James Brown, the now-retired president and COO of Denver-based Whiting Petroleum, while talking with analysts late last year.
Accessing those reserves, however, means coping with a growing anti-drilling groundswell from communities within Colorado’s densely populated Front Range, which remains the epicenter of Niobrara drilling and production. Despite the multi-billion-dollar E&P spend, and surging tax revenues, a number of Colorado cities, after being thwarted by both the state and courts, have vowed to intensify their fight to rein in the increasing number of near-town rigs and frac crews. Hoping to proactively mollify anti-drilling activists, major players Noble Energy, Anadarko Petroleum and Encana are advancing plans to centralize field operations away from the more-populated areas.
The industry is particularly up in arms over a ballot initiative that would more than double the setback in Colorado to 2,000 ft. In early September, Wyoming’s chief regulator, likewise, took the wraps off plans to increase the setback, but only to a minimum of 750 ft for rigs drilling horizontal wells.
“We believe the ballot measure proposing a 2,000-ft setback is a step in the wrong direction for Colorado,” said Chuck Davidson, chairman and CEO of the play’s largest producer, Noble Energy, during the second-quarter earnings call. “Existing setback rules, which require 500-to-1,000-ft distances from occupied structures, were just put into effect last year, and they are some of the most aggressive regulations in the country. The 2,000-ft setback, while a four-fold increase in direct distance, is a 16-fold increase in terms of total surface area affected. This would have a significant impact on development of oil and gas in certain areas of the state.”
ALL METRICS ON THE RISE
The swelling opposition, however, has yet to have any significant impact on activity. Indeed, an increasing number of rigs continue to target the source rock for the prodigious Wattenberg and Silo fields of Colorado and Wyoming, respectively, which is known interchangeably as the DJ-Niobrara, the Mancos-Niobrara or, more commonly, the Niobrara-Codell, in deference to the underlying sandstone that is the primary pay zone for some of the basin’s biggest producers, including the Wattenberg. Regardless of the nomenclature one chooses to use, drilling continues to increase. Baker Hughes data show 62 rigs actively targeting the Niobrara-Codell, as of the week of Sept. 14, up significantly from the 47 rigs drilling during the like period last year. Of those, 53 are making hole in Colorado’s Weld County, home of the 35-year-old Wattenberg, which abuts the Front Range and is the core of Niobrara-Codell activity. Only five of the total active rigs are targeting the Niobrara-Codell in the Wyoming sector of the Denver Basin, primarily in, and around, Silo field in Laramie.
In the second quarter, operators drilled 267 new wells, according to the Baker Hughes well count, up from the 258 new wells spudded in the first three months of 2014. Baker Hughes data show 266 new wells drilled in second-quarter 2013.
Meanwhile, in its most recent Drilling Productivity Report, the EIA projects that the entire Niobrara region, comprising all of northern Colorado and most of eastern Wyoming, will produce around 370,000 bopd by October (Fig. 2), with some operators reporting more than 100% year-over-year production increases. Despite severe flooding late in the third quarter that hampered field operations, Colorado’s 2013 production broke a record that had stood for nearly 60 years, as operators delivered nearly 64.1 MMbbl of oil at a daily clip of 176,500 bpd, according to data from the state’s chief regulator, the Colorado Oil and Gas Conservation Commission (COGCC). This is a significant hike from the 135,300-bopd rate during 2012.
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| Fig. 2. The latest Drilling Productivity Report projects increases in both oil (left) and gas (right) production in the Niobrara region through October 2014 (charts courtesy of U.S. Energy Information Administration). |
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Though the COGCC is unable to distinguish production by formation, the Niobrara-Codell is widely recognized as the primary contributor to the staggering 146% increase in Colorado oil production that the EIA says hit the sales lines between 2007 and 2013. In addition, the federal agency said the state’s marketed gas production rose 38% between 2007 and 2012, though state data show a drop at year-end 2013 to 4.43 Bcfd from the 4.65 Bcfd recorded at the end of 2012.
Unlike its southern namesake, the Wyoming Oil and Gas Conservation Commission (WOGCC) is able to break out production by reservoir. Last year, the state regulator shows Niobrara oil production jumping to 3.5 MMbbl, thanks largely to the more than 2.7 MMbbl produced from wells drilled in the Powder River basin. However, so far this year, the Codell sand has overtaken the overlying Niobrara in wells put on-line in southern Wyoming’s Denver-Cheyenne basin. As of Sept. 17, state records show the Codell producing 967,147 bbl of oil and 647. 653 MMcf of gas, compared to 445,951 bbl of oil and 407.794 MMcf of gas for the Niobrara. The numbers represent a significant shift from last year, when Niobrara-targeted wells in the Denver-Cheyenne basin produced 703,885 bbl of oil, compared to the Codell’s 420,349 bbl.
Regardless of which side of the border production is flowing, all Niobrara-Codell activity is under the control of independents. The sole major with substantial holdings in the play, Shell Western E&P, unloaded its leasehold last year, after which its short-lived JV partner, Quicksilver Resources, liquidated its remaining acreage.
CRACKING THE CODE
Think of the child prodigy who sails through university in two years, and you get a sense of how quickly operators have accelerated the learning curve in what was once regarded as the most technically daunting of the North American unconventional plays. Today, Encana and other operators use phrases like “very forgiving” to describe well construction in the geological goulash that characterizes the Niobrara petroleum system.
Far from a pure shale, the thermally mature Niobrara, which is said to range vertically from 275 to 400 ft thick, comprises a series of chalk, shale and fine-grained limestone. Typical drilling depths for Niobrara wells range from 7,000 to more than 8,000 ft, with ever-increasing laterals of more than 10,000 ft in some cases. The rock has exhibited total organic carbon (TOC) content ranging from 0.85 to 2.75. Owing to the ever-present brittle facies distributed between shale layers, natural fracturing is universal throughout the Niobrara, which, in tandem with hundreds of older vertical wellbores, puts a premium on geosteering for precise well placement.
Though it has yet to fully live up to its earlier billing as the Bakken-in-waiting, Niobrara-Codell well costs are as much as half those of its North Dakota counterpart. As a case-in-point, the play’s most active operator, Anadarko Petroleum, said that by the second quarter, it had cut drilling cycle times in its Wattenberg asset by as much as 40% from two years ago. During the quarter, Anadarko said wells drilled in its roughly 350,000-acre crown jewel were averaging 8.7 days from spud to release. The Woodlands, Texas, independent is running 14 rigs (Fig. 3) and plans to drill more than 360 wells during 2014. In the second quarter, Anadarko’s Wattenberg holdings averaged approximately 169,000 boed in net sales volumes, up 39,000 boed, or 30%, from the first quarter. “The growth in the Wattenberg field has been nothing short of exceptional,” President and CEO Al Walker said in announcing the quarterly earnings.
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| Fig. 3. One of Anadarko’s play-high 14 rigs drilling within its Wattenberg asset (photo courtesy of Anadarko Petroleum). |
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Today, the focal point is increasing production and estimated ultimate recovery rates (EUR) with optimum downspacing, and the evaluation of various completion and stimulation techniques taking center-stage. Operators also are looking at assessing the potential of stacked zones, which Bonanza Creek Energy says generates a “multiplier effect on value.” Along with the three benches of the Niobrara and the Codell sands, Bonanza and others are examining the prospects of the underlying Greenhorn and the underpressured J-Sands. According to the Wyoming Oil and Gas Conservation Commission, the underlying J-Sands this year contributed 150,534 bbl of oil and 33,862 Mcf of gas from wells drilled in the Denver-Cheyenne basin.
“The play grew so fast that a year ago, people weren’t talking about three different benches,” Wells Fargo analyst David Tameron told the Denver Post in December 2013.
Premier leaseholder, and top producer, Noble Energy has launched what it calls “underground laboratories” in the form of centralized, integrated development plans (IDP) that it says not only increase net present value (NPT), but reduce the environmental footprint throughout the life of the asset. At the end of the day, Noble plans to have five IDP complexes throughout its 610,000-acre Wattenberg holdings (Fig. 4), where different downspacing scenarios and completion types will be evaluated.
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| Fig. 4. Once in production, the five Integrated Development Plans being assembled by Noble Energy will occupy more than 50% of the operator’s 610,000-acre holdings (image courtesy of Noble Energy). |
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The first two IDP areas, the 61,000-acre Wells Ranch and 44,000-net-acre East Pony, were initiated late last year. At year’s end, the Wells Ranch IDP held more than 300 wells on confirmed 40-acre spacing, Noble said, adding that it expects to add upwards of 1,000 more wells at a cost of less than $4 million/well. To date, gross production from the Wells Ranch IDP reached 25,000 boed, with an expected peak of 115,000 boed by 2019.
The still-developing East Pony, meanwhile, houses 50 producing wells, also with 40-acre spacing, that thus far have produced 10,000 boed, with peak production of 150,000 boed envisioned by 2019. By then, an additional 1,300 wells will have drilled on the hub, the operator says.
Befitting the laboratory characterization of the IDP strategy, President and COO Dave Stover said Noble continues to conduct downspacing tests, including 24 and 32 equivalent wells/section, and evaluate the potential value of plug-n-perf over the traditional sliding sleeve completions in its core IDP area. “In these wells, we’re testing various completion ideas, including different fluid and proppant designs , and wells in multiple zones,” he said. “In addition, we have downhole fiber optic cables in a couple of the wells and are measuring recovery down to the individual stage level, to evaluate the effectiveness of our completion designs. Still a lot to learn here, but some strong early encouragement.”
Noble is operating nine rigs this year, with plans to double drilling activity to 680 equivalent wells/year by 2018. The Houston-based operator said its Wattenberg holdings delivered a net 95,000 boed last year.
Elsewhere, as part of its catalyst drilling program, Bonanza Creek Energy said it, likewise, feels confident with the 40-acre spacing that it has employed on its four-well Niobrara B bench pad. The wells averaged initial 60-day production rate of 463 boed, with only a 3% decline rate, compared to the average, initial 30-day production rate of 477 boed, according to the operator. The two internal wells were completed with 28 stages. In the third quarter, Bonanza planned to begin constructing a five-well pad, to be completed with 28 stages per well, and testing 40-acre spacing in the Niobrara B and C benches. To date, Bonanza Creek has drilled and completed two 9,000-ft laterals in the Niobrara B and C benches, and one 7,500-ft lateral in the Codell.
“As a result of our catalyst testing program in the Wattenberg field, we are becoming increasingly confident in 40-acre spacing, optimal lateral lengths, well configuration, and the primary recoveries achievable in the Niobrara and Codell,” said interim President and CEO Marvin Chronister, in announcing second-quarter earnings.
REDUCING THE FOOTPRINT
Encana is quick to concede that while there are intrinsic efficiencies, plans to centralize production operations away from populated areas were motivated by the concerns of Front Range communities. Early next year, the Canadian operator said that it plans to have its first hub up and running within the most concentrated portion of its estimated 49,000-acre leasehold in the DJ basin.
“The concept of the hub resulted from concerns expressed by people living in the area, who wanted to see less impact from our operations,” a spokesman said. “The centralized facility concept of the hub helps achieve this result by reducing truck traffic, air emissions, the potential for spills, and consumption of fresh water. While there is an upfront capital commitment to using this approach, it brings efficiencies to our production that will create savings over time. However, the primary reason for doing this is to address impacts.”
Reducing the environmental footprint is priority du jour, as operations inch closer to Front Range neighborhoods. The situation has reached the boiling point, with voters in some municipalities, including Fort Collins, Longmont and Lafayette, electing to ban operations within their boundaries, which the courts subsequently overturned as being contrary to state law. Nevertheless, city activists have threatened lawsuits or a return to the ballot box, in hopes of reversing the judicial rulings. In the wake of persistent environmental squabbles, operators have little choice, but to proactively shrink their respective footprints.
For Encana, that means establishing centralized hubs (Fig. 5), usually on 15-20-acre sites, capable of processing production from up to 24 pads, containing as many as eight wells each. Encana says it has employed the same concept in its leasehold in Wyoming’s Jonah field and the Piceance basin of Colorado’s Western Slope, where production typically is collected and processed several miles from the drilling location and residential areas. “This results in 92,000 in-town, oil truck miles replaced by approximately 35 miles of 12-in. pipe,” a spokesman said. “This also means that all in-town water truck activity is completely eliminated. Eliminating in-town truck traffic greatly reduces the overall amount of dust and noise, as well as the amount of off-gas produced in the area.”
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| Fig. 5. An artist’s rendition of the centralized production hub, which Encana expects to have in operation in the DJ-basin by early 2015 (image courtesy of Encana). |
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This year, Encana is operating six rigs and plans to drill 55 to 60 net wells. The company says that it has forecast annual capital spend of $300 million to $350 million in its DJ basin leasehold.
Anadarko, meanwhile, has been remotely fracing Wattenberg multi-well pads since September 2013, with four locations in operation. The operator’s Stim Centers consolidate frac spreads and proppant in central locations—as far as possible from populated areas—from which high-pressure piping is used to remotely frac wells on multiple pads. While new to Colorado’s DJ basin, the process was developed some time ago for use in Jonah field, and is used extensively in the Bakken.
Noble Energy, as part of its Wells Ranch IDP, in October 2013 commissioned the companion centralized processing facility that, like Encana, handles production from a number of satellite wells. In addition, Noble recently unveiled Colorado’s LNG plant. The newly unveiled Keota plant has a designed processing capacity of 30-45 MMcfd, with much of the produced LNG volume to be used to fuel Noble’s equipment.
INDEPENDENTS RULE
While independents of all stripes wholly control the liquids-rich Niobrara-Codell play, near-term activity plans reflect major-sized capital being spent to exploit increasingly attractive recovery rates. In December, the Denver Business Journal said Anadarko and Nobel were expected to close out 2013 with Niobrara expenditures of up to $1.7 billion, each, with the latter saying it may invest upwards of $10 billion in the DJ basin by year-end 2018.
Though other players may be shelling out appreciably less per capita, drilling plans for the remainder of this year, and into next, suggest that the collective Niobrara-Codell expenditures are in no danger of dwindling anytime soon.
Home-grown Synergy Resources Corp. added nearly 2,000 net acres to its Wattenberg leasehold in November, bringing its cumulative holdings to some 53,151 net acres, spread out between the core of the field and the northeastern Wattenberg extension. Synergy has earmarked between $200 million and $210 million in fiscal 2015, with a primary objective of exploring the stacked play potential of the Niobrara, Codell and Greenhorn formations.
In August, Synergy, which controls an aggregate 298,000 net acres in Colorado and Nebraska, updated the latest production from its four Wattenberg pads, each comprising an average of 5.5 wells completed, with an average of 21 frac stages/well. After a mean 142.5 days of production, the quartet was delivering an average of 340 boed/well. As of mid-August, the most recent, six-well Union pad was averaging 566 boed/well after 30 days, which CEO Craig Rasumson described as “the best we have achieved so far.” At that time, Synergy was drilling a third well on its Kiehn pad, where it plans to drill eight wells, split evenly between the Niobrara C bench and the Codell. A third well, likewise, was being drilled on its Weld 152 pad, which eventually will house six wells, comprising three Codell, two Niobrara B and one Niobrara C bench wells.
Continuing its ongoing push to diversify its gas-dominant production and reserve portfolio, Houston’s Southwestern Energy Co. earlier this year acquired the estimated 302,000 net acres formerly held by the Quicksilver Resources and Shell Western E&P JV. The $180-million acquisition includes prospective, stacked Niobrara acreage in Colorado’s Sand Wash basin, where the company began a five-well drilling program in June. Southwestern says the drilling program will include four vertical test and one horizontal well, targeting a roughly 400-ft section in the basin’s rich condensate and oil window. “We will invest approximately $280 million in a new project in the Niobrara formation, in the Sand Wash basin,” said CEO Steve Mueller in announcing second-quarter earnings.
PDC Energy continues its aggressive Niobrara drilling campaign, operating five rigs on the roughly 97,000 net acres that it controls in Wattenberg field, of which 97% are held by production (HBP). PDC drilled 60 gross horizontal wells in the first quarter and plans to drill 123 operated wells throughout the year, based on spacing of 16 wells/section. The independent said it is targeting the three benches of the Niobrara and the Codell, all of which have yielded production.
For the first six months, PDC says its Wattenberg leasehold has yielded nearly 2 MMbbl of oil (1.961 MMbbl), up 56.1% from the like period last year, as well as 386,300 bbl of NGLs and 4.338 Bcf of natural gas, up 42.2% and 48.8%, respectively, year-on-year.
After unloading its 32,182-net-acre Big Tex prospect in the Delaware basin of West Texas to an undisclosed buyer late last year, Denver’s Whiting Petroleum Corp. is funneling much of the $150.1-million proceeds into accelerating development of its 128,721-net-acre Redtail development in Weld County, targeting both the Niobrara A and B benches. In the second quarter, Redtail produced 7,235 boed, up 59% from the prior quarter. In June, Whiting spudded its 30F Super Pad in the Horsetail Township of Redtail, where it is now testing a 32-well spacing pattern, targeting all three Niobrara benches.
Bonanza Creek Energy is running four rigs, as it continues to evaluate the stacked play potential within the 70,100 net acres that it holds within its flagship Wattenberg Niobrara/Codell asset, Fig. 6. This year, the independent says 77% of its budgeted CAPEX is earmarked for the Wattenberg, with plans to drill 121 operated wells.
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| Fig. 6. One of the four rigs that Bonanza Creek Energy is running to target the Niobrara and underlying horizons (photo courtesy of Bonanza Creek Energy). |
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Carrizo Oil and Gas is running a single rig and plans to drill 11 net (32 gross) Niobrara wells in 2014 on the 39,700 net acres that it controls in Colorado’s Weld and Morgan counties. The thrust of the drilling program this year is testing 60- and 40-acre downspacing in the Niobrara. Carrizo, which also plans to complete 43 gross (15 net) wells this year, is participating in Super Pads with Noble and Whiting, to test the three benches of the Niobrara at various spacing. Carrizo says it is running two coiled tubing-activated, 75-stage sleeve systems as a possible alternative to the current 40-stage plug-and-perf completions.
This year, Carrizo also began drilling its second 40-acre, Niobrara B-A-B downspacing pilot in its Hemberger area in Weld County. Current plans call for the pilot to include three wells in the B bench and two wells in the A bench, with the laterals spaced approximately 300 ft apart.
With the addition of 13,000 net acres in the second quarter, EOG Resources now holds 85,000 net acres of prospective, stacked, Niobrara/Codell pay zones in the southern Wyoming sector of the DJ-basin. EOG has a planned drilling program of 39 net wells this year from its multi-well pad in Laramie County, Wyo., where it is evaluating the economics of 9,000-ft laterals.
The results of six recent, 9,000-ft Codell wells showed average initial production (IP) rates of around 1,269 bopd, while three recent Niobrara wells with 3,600-ft laterals delivered IP rates of 690 bopd. The EOG Codell acreage is estimated to hold potential reserves of 125 MMboe, while its identified, 235 net Niobrara locations hold estimated potential reserves of 85 MMboe.
ConocoPhillips, which controls roughly 130,000 net acres prospective for the Niobrara, is running a one-rig appraisal drilling program this year, with plans to drill 19 horizontal wells. The operator continues to evaluate a new completion design, with early results showing more than a 600-boed increase in average production.
Denver’s Bill Barrett Corp. is running three rigs and, for the time being, plans to drill 56 extended reach wells during 2014 within its northeastern Wattenberg leasehold. The independent controls 76,115 net acres in the DJ basin, which at year-end 2013 produced 1.28 MMboe, where its typical well designs feature 9,000-ft laterals and 40 frac stages. 
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