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Posted on 11/21/2013 11:03:33 PM PST by ckilmer



Vol. 234 No.9



A rig drills for oil in Colorado’s liquids-rich basins against the backdrop of the Rocky Mountain range. Source: Colorado Geological Survey.
A rig drills for oil in Colorado’s liquids-rich basins against the backdrop of the Rocky Mountain range. Source: Colorado Geological Survey.

While the byzantine Niobrara shale that underlies a substantial portion of the U.S. Rockies, and beyond, is not for the technologically skittish, recent production data suggest that the resolute independents, who dominate the liquids-rich play, are steadily getting a handle on its unrivaled geological complexities.

Even though the multi-horizon Niobrara may have a long way to go, to reach its earlier billing as the Bakken-in-waiting, both oil production and drilling activity continue to increase, largely within its Colorado hub. As currently defined, the sprawling Niobrara, which has produced at considerable rates from vertical wells for the better part of a century, extends across northeastern Colorado, southeastern Wyoming and into northwestern Kansas and southwestern Nebraska. The epicenter of horizontal drilling activity continues to fall primarily around the giant Wattenberg field of Colorado (Fig. 1) and, to a much lesser degree, the Silo field of Wyoming, both of which are sourced by the Niobrara.

Colorado’s oil and gas basins. Source: Colorado Geological Survey.
Fig. 1. Colorado’s oil and gas basins. Source: Colorado Geological Survey.

Based on its fairway in the Denver-Julesburg (DJ) basin and close alignment with the underlying Codell sandstone (Fig. 2), the primary pay zone for the billion-barrel-plus Wattenberg field, the play is known interchangeably as the DJ-Niobrara and the Niobrara-Codell. Regardless of what you choose to call it, however, the Niobrara is undoubtedly the most geologically daunting of the North American shale plays.
DJ basin stratigraphic column, showing multiple target zones. Source: PDC Energy.
Fig. 2. DJ basin stratigraphic column, showing multiple target zones. Source: PDC Energy.

“The structuring and very complex faulting can really create havoc with drilling horizontal wells in the Niobrara,” said Jack Wiener, Halliburton’s Denver-based technical advisor for geosciences and subsurface characterization. “Well placement is one of the critical challenges operators face here today. Now that they’re going lateral, when they cut these faults they’ve had to react on the fly and try to get back to where they need to be in the target zone. A lack of planning can seriously impact costs and ultimate production.”


Despite the unprecedented geological challenges, a growing anti-fracing backlash, and the sudden withdrawal of one of the lone majors to have announced a once-promising exploration program, the undaunted operators that remain are increasing both production and drilling activity.

The latest data available from the Colorado Oil and Gas Conservation Commission put the state’s oil production at the end of 2012 at a 50-year high, at just under 48 MMbbl. While the state’s chief regulator does not separate formation-specific production in its cumulative statistics, nearly everyone agrees that the increased oil output comes directly from the Niobrara and underlying Codell formations. “The Niobrara is the King Kong,” Pete Stark, vice president of industrial relations for IHS, told the Denver Post in March.

According to Colorado’s northern counterpart, Wyoming oil production increased to just over 57.5 MMbbl in 2012, representing an 11% increase since 2009. Thus far, during 2013, Wyoming oil producers have pumped more than 29.6 MMbbl, says the Wyoming Oil and Gas Conservation Commission.

While the Wyoming regulator, like its Colorado counterpart, does not break out production by formations, the state agency said that nearly a third of the state’s production comes from vertical and horizontal wells in the prolific Powder River basin. Despite earlier excitement over Wyoming’s Niobrara prospects, primarily in Goshen, Platte and Laramie counties, the state has never come close to approaching the level of Colorado Niobrara production. Chesapeake, for instance, put its Colorado Niobrara properties on the block, and says it will concentrate its drilling activity in the Powder River with Chinese partner CNOOC. In fourth-quarter 2012, Chesapeake had 10 rigs drilling in the Power River basin.

Like production, the average rig counts in both Colorado and Wyoming are running slightly ahead of last year. According to Baker Hughes, 52 rigs were active in the DJ-Niobrara as of Aug. 20, compared to 45 for the like period last year. Of those, 49 were drilling in key Colorado counties, including 42 in Weld County, home turf of the Wattenberg. Three rigs were drilling in the Wyoming portion of the Niobrara, all in Laramie County. Conversely, in the second quarter, an estimated 293 new wells were drilled in the DJ-Niobrara, according to the new Baker Hughes U.S. land well count, which represents a 104-well drop from the 397 drilled during the like 2012 period.

Meanwhile, going forward, Colorado’s chief regulatory agency had issued 2,306 drilling permits for horizontal and directional wells from common pads as of August 7, compared to 3,775 similar permits issued for all of last year. Of the total permits issued last year, 1,826 were for wells in Weld County, which is recognized as the spark for the Niobrara tight oil play. To the north, Wyoming had issued 1,399 horizontal drilling permits as of August 19, according to state data.


The thermally mature Niobrara formation, which vertically ranges in thickness between 275 ft and 400 ft, is described in the literature as a Cretaceous hybrid shale/carbonate reservoir, deposited in a deep marine environment, with areal variations in reservoir properties and tectonic overprint. Although generally identified as a shale play, heterogeneous Niobrara reservoirs are comprised primarily of limestone or chalk intervals. Over the past few years, much of the exploration and development activity has shifted to the myriad sub-plays, including the lower, carbonate-rich Niobrara benches and the underlying Codell formation. Typical drilling depths for Niobrara wells range from 7,000 ft to more than 8,000 ft, with ever-increasing laterals of up to 9,000 ft.

Prospects for the Niobrara spiraled in October 2009, when EOG Resources brought in its Jake horizontal well in Weld County. Even though Jake, as of early last year, was still producing 50,000 bbl/month, EOG does not list the Niobrara within its core plays. Jake was followed in early 2010 with Noble Energy’s Gemini well, also in Weld County, that was completed with a 16-stage frac treatment and produced 1,100 bopd at its peak.

Comparisons to the Bakken quickly followed and attracted a host of operators, which Halliburton’s Wiener said were caught unawares by the geological complexities, and, just as quickly as they arrived, they retreated. “Those who have endured, those who have worked with us and more consciously tried to evaluate and truly understand this play, are still here today,” said Wiener, who in his former stint as an operator engineer, drilled his first Niobrara well more than 20 years ago.

Niobrara pacesetter Noble Energy is one of those operators that, most definitely, has endured, and like all those who remain, has concentrated on improving reservoir drainage, which has included extending lateral lengths. “We continue to see the performance of the 9,000-ft extended-reach laterals, on average, in excess of the 750,000-bbl equivalent-type curve,” Noble President and COO David Stover said during the second quarter-earnings call. “And, a number of the wells are performing in line with 1-million-bbl equivalent EUR (estimated ultimate recovery).”

Stover said longer laterals are extending to the Codell in the greater Wattenberg area that, he said, are “performing in line” with Niobrara wells of similar length. “We’re currently testing our first long lateral at Codell,” he said. “With the entire 300-ft vertical column through the Niobrara and Codell observed to be productive, we have yet to see any production interference amongst tightly spaced Niobrara B wells and A, C and Codell completions.”

“Most of the established operators here understand the Niobrara, but not the ones who are coming in now and not doing their homework,” said Dr. Kumar Ramurthy, Halliburton technical manager for the Rockies, West Coast and Alaska.


More recently, the Niobrara has become a political football in Colorado, pitting anti-fracing activists against the state, which claims their attempts to ban drilling in a number of communities oversteps their authority. Nevertheless, Fort Collins drilling opponents say they have sufficient signatures on a petition that would clear the way for a five-year fracing moratorium within the city limits to be put before voters in November. Similar initiatives are underway in Broomfield, Loveland and Boulder. Last year, Longmont voters banned fracing within its boundaries, which spurred a lawsuit by the Colorado Oil and Gas Association.

As development accelerates in the Denver basin, the Colorado Geological Survey (CGS) has taken a novel approach to easing the fracing backlash. The CGS recently unveiled an online-accessible Niobrara Calculation Tool that it says “helps citizens or planners understand the geologic conditions that exist beneath their property” and determine any impact fracing may have on groundwater, Fig.3.

The Colorado Geological Survey’s Niobrara Calculation Tool depicts a cross-section of the Denver basin, showing the various rock layers. The Niobrara strata are so deep that they are actually below sea level in parts of the basin. The tool is available at Source: Colorado Geological Survey .
Fig. 3. The Colorado Geological Survey’s Niobrara Calculation Tool depicts a cross-section of the Denver basin, showing the various rock layers. The Niobrara strata are so deep that they are actually below sea level in parts of the basin. The tool is available at Source: Colorado Geological Survey .

“The tool is designed to help people visualize the spatial relation of hydraulic fracturing in the Niobrara formation to the important freshwater aquifers. The tool will show the average depth to the Niobrara formation at any selected point or address on the map. It will also show the minimum thickness of the shale barrier (Pierre shale) that separates the Niobrara strata from freshwater aquifers. The tool also provides the depth of the deepest fresh water aquifer at any spot on the map,” the CGS says on its website.


In early August, Shell Oil announced that it will sell off its Niobrara holdings in the Sand Wash basin of northwestern Colorado, only eight months after signing a 50-50 exploration JV with Quicksilver Resources, and four months after releasing plans to drill 17 Niobrara wells in Routt and Moffat Counties. Shell cited disappointing second-quarter earnings, primarily from its North American shale plays, as the reason for the abrupt pull-out. Consequently, nearly all Niobrara activity is now in the hands of independents, and a sampling of activity going forward suggests they remain committed to the play.

Noble Energy averaged a record 90,000 boed from its play-leading DJ basin holdings in the second quarter, representing a 22% increase over the like 2012 period. The Houston independent plans to run an average 10 rigs the remainder of the year and expects to drill up to 300 horizontal wells.

Noble spudded more than 130 horizontal wells in the first half within its 640,000 net acres, 80% of which are in the oil window. Of its leaseholdings, 410,000 net acres are in the core Wattenberg area, while the remaining 230,000 net acres are spread across northern Colorado. Noble says its drilling rate represents the highest level of horizontal activity in the company’s history.

“We completed 31 wells in the month of June, with 604 stages pumped, a record for us and significantly above our prior record of 26 wells and 500 stages pumped in October of last year,” Stover said during the second-quarter earnings release. “We’ll continue to transition to larger pads, more centralized production, and water handling facilities and gathering systems to support our increasing levels of activity.”

Anadarko Petroleum said it plans to drill more than 300 wells this year in the 350,000 net acres that it holds in its Wattenberg area leaseholding. The Woodlands, Texas, operator ran 12 rigs in the second quarter and drilled 83 horizontal wells, Fig. 4. Quarter-over-quarter production increased by nearly 7,000 boed, to an average of approximately 52,000 boed.

Rigs at work within Anadarko’s Wattenberg Niobrara leasehold. Source: Anadarko Petroleum.
Fig. 4. Rigs at work within Anadarko’s Wattenberg Niobrara leasehold. Source: Anadarko Petroleum.

PDC Energy,
after unloading non-core Colorado gas assets and announcing a public offering of 4.5 million shares of common stock in early August, said it would accelerate its 2013 drilling program with a primary focus on the approximately 98,000 net acres it holds in the Wattenberg area, of which 95% is held by production (HBP). The Denver-based independent added a third rig in May and plans to drill at least 69 Niobrara wells this year. The independent estimates 2,000 gross horizontal locations remain to be drilled within its holdings.

The home-grown operator has earmarked capital expenditures of $280 million for the Wattenberg in 2013, which will include 48 re-fracs and recompletion stages. PDC Energy increased production 40% to 15,019 boed in the second quarter, from the 10,813 boed produced in the first quarter last year. The company has set a 2013 average target of 15,039 boed with an average per well-EUR of 335,000 boe.

Quicksilver Resources says that it intends to maintain its planned drilling schedule this year, even with the sudden pull-out of its short-lived JV partner, Shell Western E&P Co. The Fort Worth, Texas, independent says it plans to participate in seven wells in 2013, in the 167,000 net acres that it held prior to the JV, largely in the Sand Wash basin. Quicksilver said it has identified 1,200 ft of productive Niobrara across a distance of 35 mi, in an east-to-west direction and 15 mi in a north-to-south band across the leasehold. The operator drilled four wells last year, while completing three and re-fracing two additional wells with treated slickwater. 

Bonanza Creek Energy plans to double drilling activity in 2013 within its core Wattenberg leasehold. Bonanza says around 15,000 net acres, or about half its total lease holdings, are prospective for the Codell. Bonanza is operating four rigs in the play (Fig. 5) and, during 2013, plans to drill a cumulative 72 wells in the Niobrara B and C benches, and the Codell. Bonanza said 56 wells planned for the Niobrara B will be drilled with 4,000-ft laterals, while two will test 9,000-ft extensions. The independent also plans to drill six B bench wells in a 40-acre spacing test; while four, each, will target the C bench and the Codell. 

A rig drilling within Bonanza Creek Energy’s Wattenberg holdings. Source: Bonanza Creek Energy.
Fig. 5. A rig drilling within Bonanza Creek Energy’s Wattenberg holdings. Source: Bonanza Creek Energy.

Synergy Resources,
 likewise, completed a common stock offering in June, which raised $78.3 million net, nearly all of which will be used for both horizontal and vertical drilling in the 17, 046 net acres that it holds in the Wattenberg field. In a related development, in March 2013, Synergy completed an exploration agreement with Dallas, Texas-based Vecta Oil and Gas that increased its Northern DJ basin acreage position to 20,040 net acres.

During the first half of fiscal 2013, Synergy drilled and completed 27 vertical wells in Wattenberg field, and participated as a non-operator on an additional 10 horizontal wells in the core area. 

Whiting Petroleum has assembled a 120,513-gross acre (87,559-net acre) leasehold in its Redtail Niobrara prospect in the northeastern portion of the DJ basin. Whiting is operating two rigs and plans to add a third in October.

Bill Barrett Corp. plans to drill around 45 wells in second-half 2013, primarily targeting Niobrara C and Codell prospects. The Denver independent added 42,900 net acres to its leasehold last year, giving it an aggregate 76,475 net acres. wo-box_blue.gif

New-Age technologies help to untangle Niobrara complexities

Homogeneity is not a concept that can be readily applied to the lithological hodgepodge that is the Niobrara shale. Consequently, between the pervasive non-uniformity and complexities of its geological framework, landing wells properly to affect optimum reservoir drainage remains a daunting challenge throughout the organic-rich play. Over the past few years, new-generation geophysical and microseismic technologies have been employed to help the play-dominant independents get a firmer grasp of the highly variable natural fracturing, to increase estimated ultimate recoveries (EUR) in what was once hyped as the Bakken-lite.

Halliburton has participated in the hydraulic stimulation of some 95% of the Niobrara wells drilled and completed to date, says Dr. Kumar Ramurthy, Denver-based technical manager for the Rockies, West Coast and Alaska. “We have developed and introduced some very sophisticated technologies here, to help operators execute their wells in an optimum manner to maximize production,” he said. “We also were the first service provider in the basin to help operators reduce their drilling days.”

Among the latest-generation technologies that Halliburton unveiled for Niobrara operators is the Seismic-2-Stimulation integrated workflow. The technology, according to Halliburton, “generates elegant solutions for subsurface understanding, reservoir optimization, completion design and production enhancement.” The workflow helps operators pinpoint Niobrara sweet spots and identify a cost-effective well placement strategy for effective stimulation for multi-well horizontal pads, Fig. 1.

A Halliburton 3D structural model showing Niobrara formation tops in Wattenberg field.  Source: Halliburton
Fig. 1. A Halliburton 3D structural model showing Niobrara formation tops in Wattenberg field.  Source: Halliburton

“Basically, we developed a 3D structural model that integrates the vertical well information, and this integration allows us to actually pick the different formation tops within the Niobrara,” says Jack Wiener, Halliburton’s Denver-based technical advisor for geosciences and subsurface characterization. “We pick all of the fault cuts that are present in these wells, which cause the structural complexity, and by removing a geologic section out of the borehole, along with a great deal of reservoir characterization and petrophysics from the log, we can tightly integrate with the 3D seismic data and give the operator a very good handle on what the structural framework looks in a particular area. This is particularly beneficial, when an operator is pad drilling with eight to 16 horizontals from a single location.”

Ramurthy said that as part of Halliburton’s holistic workflow, the company recently introduced its distributed fiber-optic sensing technology to multi-well Niobrara drilling pads. The new-generation technology provides operators with the capacity to manage the reservoir, wellbore and completion in real time by monitoring temperature profiles along the entire well path at user-selected intervals.

Unlike standard reservoir monitoring technologies that require sensors within a physical device, distributed temperature sensing comprises only a surface instrument that uses a laser and photo detector. With distributed fiber-optics technology, a pulse of laser light is fired down the fiber, which basically turns the entire length of the glass fiber into thousands of sensing points. The signals that are reflected back can then be analyzed, among other purposes, to monitor acid and fracturing treatments in real time to observe stimulation fluid entry points into the reservoir.

“We first used the DTS technology in the Niobrara on a Noble Energy pad, and we now are in the process of conducting fiber-optic science projects on both Noble and Anadarko pads,” Ramurthy said.


Owing to the presence of brittle facies distributed between shale layers, natural fracturing is common throughout the Niobrara. High calcite concentrations, particularly in the upper Niobrara, contribute to the development and re-activation of complex natural fracture networks during hydraulic fracturing. Consequently, the distinctive complexity of the Niobrara, coupled with its distributed fault and fracture systems, lends itself to diagnostic tools, such as microseismic monitoring, to help operators enhance hydraulic fracture performance to optimize production, says ESG Solutions of Ontario, Canada.

Accordingly, ESG recently acquired and processed microseismic data for a 19-stage, horizontal, plug-and-perf hydraulic fracture program in the Codell formation in Colorado. Afterwards, the operator requested microseismic data to be re-processed for a second, 19-stage Niobrara horizontal frac program, completed in close proximity to the Codell well, Fig. 2. Specifically, the operator wanted to evaluate connectivity between the two stimulated wells, particularly in the region where the two wells intersect, and determine the effect of nearby faults and existing fracture systems on well stimulation and fracture development.

Evidence of fracture interaction between the Codell well (A) and Niobrara well (B).  Events demonstrate a westward growth during the treatment of Well B (top), while during stimulation of Well A, events migrate eastward into a previously stimulated zone (bottom).
Fig. 2. Evidence of fracture interaction between the Codell well (A) and Niobrara well (B).  Events demonstrate a westward growth during the treatment of Well B (top), while during stimulation of Well A, events migrate eastward into a previously stimulated zone (bottom). 

According to ESG, gamma and resistivity logs taken along the treatment wells indicated lateral heterogeneity along the wellbores, further adding to the Niobrara geological complexity. To account for velocity variations caused by subsurface heterogeneities, as well as changes to the reservoir resulting from fracture stimulation, velocity models were refined using proprietary velocity inversion methods. Two separate velocity models were developed and used for various stages in the Codell well, and four velocity models were used for the Niobrara stimulation.

The models detected considerably more seismicity in the Niobrara, which was determined to contain significant amounts of calcite, which may encourage more efficient flow pathways (macro-porosity), thereby allowing fluid to bypass the intended treatment zone. Vertical event growth was observed in both wells, which ESG says, is likely due to faulting in the area. Microseismic results for the first well indicated that the majority of events were located above the treatment well and in the Niobrara formation, rather than in the target Codell sandstone.

A large cluster of events was located during stage 9 of the Codell well and, in addition to clustering near the wellbore, the events exhibited considerably higher, apparent stress than most other events in the well. Apparent stress describes the amount of stress or energy released during rock failure and may indicate the ease with which the rock formation breaks or fails. In areas with pre-existing planes of weakness, such as faulting, where the rock will more readily fracture, and higher apparent stress may be observed. Since fault activation generally is associated with larger apparent stress, the cluster of events was interpreted to be caused by faulting near the wellbore. The orientation of the suspected fault, associated with events during stage 9, aligned with events detected during stage 7 in the Niobrara well. For the Niobrara well, a number of event clusters appeared to correspond to changes in gamma and resistivity measurements. Evaluation of apparent stress reveals that high energy release during a number of the later stages in the well likely corresponds with fault activation.

Moreover, ESG said that evidence strongly suggested that fluid communication developed between the Codell and overlying Niobrara wells. A shallow westward growth pattern was observed during the stimulation of the Niobrara well, while the Codell well appeared to re-stimulate the same area, with events growing in an eastward direction. In addition, pressure within the Niobrara well was observed to increase during the treatment of the later stages of the underlying Codell well, in particular during stages 18 and 19. Following the stage 19 stimulation of the Codell well, a large-magnitude event was detected during pump shutdown at the toe of the Niobrara well, suggesting stress relief through the wellbore. ESG concluded that re-stimulation of a previously stimulated zone reduced the effectiveness of the Codell frac treatment.


Two horizontal wells illustrating the horizantal transverse isotrophy (HTI) roductivity correlation to anisotropy anomaly maps. Source: Global Geophysical Services.
Fig. 3. Two horizontal wells illustrating the horizantal transverse isotrophy (HTI) productivity correlation to anisotropy anomaly maps. Source: Global Geophysical Services.

Meanwhile, Global Geophysical presented an overview at last month’s Unconventional Resources Technology Conference in Denver, of how it has effectively used azimuthal anisotropy observed in surface seismic velocities to predict fracture density and orientation in the Niobrara. Last year, Global completed a multi-client, full-azimuth 3D seismic survey encompassing some 800 sq mi in Silo field of southeastern Wyoming. The survey was orchestrated to serve as the basis for a regional structural interpretation and azimuthal velocity analysis of the Silo segment of the Niobrara, Fig. 3. According to Global, the 3D survey integrated seismically-derived rock attributes, well and production data, as well as regional structural interpretation to better understand the Niobrara’s natural fracturing and to reduce drilling risk.  wo-box_blue.gif

TOPICS: Business/Economy
KEYWORDS: niobrara; shaleoil; silofield; wattenbergfield

1 posted on 11/21/2013 11:03:34 PM PST by ckilmer
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To: thackney

Judging by this, it looks like the niobrara wattenberg formation will produce about 157,000 barrels a day in 2013 or roughly the same as last year.

But I could be wrong about that. I may have conflated the wattenberg formation with all of colorado. Because it would make more sense that production would have increased—except that it looks like drilling is down. ,,, because only a couple of the independents mastered the formation.

What do you gather from this article.

A side note on this is that the complexity of the wattenberg formation ie —the complex fracture zones— suggests that mere complexity will not prevent the oil men from cracking the code in the Monterrey formation in California.

2 posted on 11/21/2013 11:10:48 PM PST by ckilmer
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To: ckilmer

I may have conflated the wattenberg formation with all of colorado.

I think so.

3 posted on 11/22/2013 5:19:07 AM PST by thackney (life is fragile, handle with prayer)
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To: thackney

here’s oklahoma oil production.

both oklahoma and colorado oil production are going straight up. Oklahoma has has put on about an extra 95,000 barrels@day and Colorado has put on about an extra 45,000 barrels@ day in the last year

between them—they’ve added about 140,000 barrels@ day of production in the last year.

new mexico oil production is also rising fast but from a low base.

utah and wyoming oil production are also rising but from low bases as well and not as fast.

I didn’t look carefully but new mexico utah and wyoming between them might add another 15,000 barrels@ day of production in the last year.

4 posted on 11/22/2013 10:42:42 AM PST by ckilmer
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