DJ basin

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Introduction

The Denver-Julesburg Basin, or commonly referred to as the DJ basin, is centered on the eastern side of the rocky mountains and extends from just south of Denver all the way to southeast Wyoming, western Nebraska, and western Kansas. The DJ basin is a large asymmetrical syncline that is responsible for 80% of crude oil from Colorado— making it the highest producing oil and gas basin in Colorado.

Location and orientation of Denver-Julesburg Basin

History

Geological

The DJ basin is as young as 300 million years old and was formed with the Rocky Mountains during the Colorado orogeny. During this time, a large inland sea split North America down the middle—creating the Western Cretaceous Interior Seaway. This sea deposited a thick layer of cretaceous sediment in the basin. Tens of millions later and the end of the Cretacous period is marked by the Laramide orogeny. The laramide orogeny reshaped this large basin into many structural basins. Mountain building in this area began due to increased lateral compression resulting from tectonic movement. Furthermore, the Cretaceous Interior Seaway shrunk towards the gulf of mexico— leaving behind hundreds of millions of years of sedimentary deposits. Through petroleum processes, a stratigraphic puzzle of hydrocarbon rich source rocks formed to one day be produced.

Production

Oil was first discovered in Florence Field in 1881. Since the discovery, the Denver basin is responsible for upwards of 50,000 producing oil and gas wells. With over 1500 oil and gas fields in the basin, oil and gas operations have carried on for over a century. Of the 1500 total wells in the basin, the urban corridor east of the rocky mountains houses 96 fields. The urban east corridor is also responsible for over 50% of the production in the basin. Multiple formations are responsible for these successful wells— mostly located in the Wattenberg field just north of Denver. Wattenberg field is responsible for half of the 3.5 TCFG that is produced from Sussex sandstone, Codell sandstone, and J sandstone layers.  Upwards of 1 BBO have been produced from the DJ basin, and the highest producing field is Adena with roughly 60 MMBO from the D and J sandstones.

Petroleum Elements

Source Rock & Migration

Cross-section of Denver-Julesburg Basin

Source rocks containing hydrocarbons in the Pierre Shale Sandstones Play are underlying shales of the Niobrara, Graneros, and Mowry. Based on thermal and burial history of cretaceous source rock, the time frame for oil generation is late cretaceous period to early tertiary time. The low permeability and low thermal maturity of the Niobrara Biogenic gas play suggest the gas was generated in the Niobrara formation. The Dakota group D and J sandstones play provides both reservoir and migration drainage pathways for oil. Thermal maturity across the northern region of the basin indicates values ranging from 0.4 to 1.14 percent Rm. Source rock shales across the basin measured 0.24 to 67.5 percent. Paleozoic Black shales in the north region of the basin have high potential as source rocks. These rocks expelled oil with low levels of thermal maturity. The likely time period for oil generation and migration in the Permian Pennsylvanian play is late Cretaceous to the majority of tertiary. Source rocks in the Wattenberg Niobrara/Codell gas play are organic rich Mowry, Graneros, and Niobrara formations with a thermal maturity of 0.8 percent Rm or greater. The deeper play in that field focuses on the J sandstone and according to lower levels of thermal maturity, gas generation and migration did not occur until late tertiary time.

Reservoir

Stratigraphy column

Majority of the basin’s oil and gas production has been from Cretaceous rock. Cretaceous rock lies near the front central range and is approximately 10,000’ deep. This rock consists mostly of deltaic and marine detrital units. Several reservoirs contain oil producing cretaceous rock— although, the Lower Cretaceous “D” and “J” sandstones account for around 90% of oil and gas production. In the Pierre Shale Sandstones play, oil and gas is produced from the Sussex and Shannon sandstones. These reservoirs reach 4,500’ to 5000’ in depth and range from 3’- 50’ in thickness. and include seven accumulations. Shale and shallow chalk reservoirs of the Upper Cretaceous Niobrara formation house dry non-associated gas. Gas is stratigraphically trapped inside fine-grained, low permeability, and high porosity chalks. Depths range here range from 800’ to 3500’ and averages 500’ in thickness. Oil is produced from fracturing the Niobrara and immediate underlying Codell sandstones. The Wattenberg Niobrara/Codell unconventional play is located north of Denver in the deeper part of the basin. The primary focus is the stratigraphically trapped marine sandstones in the formation. Low porosity and permeability categorize these beds as tight gas sands— thus, require hydraulic fracturing operations at depths from 3000’ to 8000. The Dakota group J and D muddy sandstones are both lower cretaceous zones that cover nearly half the province in the northeastern region of the basin. Fine to medium grained facies resulted from a delta environment. The Dakota group has a max thickness of 500’ and averages 25’ for average producing thicknesses. Depths range from 4000’ to 9000’.

Trap & Seal

Stratigraphically trapped hydrocarbons are primary in the Denver basin. The Pierre Shale sandstone play has five stratigraphic and one combination trap. Pierre Shale in the Upper Cretaceous zone contains marine sandstones with oil and gas. These sandstones maintain proximity to the margins of the sand ridges that define the bodies of sand. The marine shales updip causing a seal. The Niobrara Biogenic gas play operates under organic rich chalks, high porosity, and low permeability enclosed in a stratigraphic trap. The overlying Pierre Shale provides efficient trapping mechanisms. The Dakota group and J sandstones play are primarily trapped stratigraphically from overlying marine mudstone. J sandstones are trapped by anticlinal closure. Structural traps along the front range were formed during the Laramide orogeny. Based on the decreasing thickness of strata towards the west, near the Hartville uplift, structural traps date back to the Paleozoic era; predating the migration of oil. Up towards the Nebraska panhandle, trapping mechanisms updip and overly with low porosity and permeability. The low relief structural noses and mudstones are primary trapping mechanisms for Pennsylvanian plays in that region. J sandstone deep gas requires hydraulic fracturing for production from fine grained quartz of marine sandstones. Organic rich shales formed brittle reservoir rocks through regional tectonics and bounding shales.

Infrastructure and Engineering

Environmental stewardship is important for success in the DJ basin. 30’ sound walls are used to dramatically reduce noise and light pollution. Sound levels are reduced by 25% with equipment of this sort. Further measures include enclosing diesel engines, pumps, and completion equipment. A normal hydraulic fracturing operation exceeds 80dB at a 500’ radius. Most of the basins operators install the sound walls during drilling and completion stages. Electric drilling rigs and quiet completion rigs make noise pollution much more manageable in highly operated areas.

Hotspots in oil and gas production exist throughout the Denver basin. The Niobrara chalky shale and Codell sandstone directly beneath are produced similarly. The small water to oil ratio allows for minimal amounts of produced water to deal with. Production in the DJ basin is economical since it never needs very much artificial lift. Plunger lift is most common in the newer horizontal wells, and pump jacks were used more commonly on the older wells. The Completion phase differs the most between the Codell and Niobrara. Codell is sandstone so less proppant is used since less permeability is required. Codell is a smaller frac' job so operations don’t induce as much permeability and this allows for cheaper input costs. A major player is Anadarko with about 25% of the wells drilled— PDC Energy, SRC Energy,  Extraction Oil and Gas, and Noble Energy. Water logistics in the Denver basin pose a threat to source water for frac jobs. Companies are struggling to acquire adequate amounts of water since rain is hard to come by in this region. Because of this, cross-link is becoming more popular in this region than slickwater drilling fluid. Geo steering is very common throughout the Denver basin since tectonic movement has caused many faulted formations.

Future Potential and Challenges

A good amount of risk in producing in the DJ basin is associated with the political climate and regulatory actions taken towards oil and gas operations in Colorado. The Air Quality Control Commission of Colorado has taken steps to mitigate methane leaks from oil and gas operations across the state. High frequency gas leak systems are now required upon construction of a well, and through early production. Natural gas venting during the early completion stages is also banned. Oil and gas operations will have to continuously monitor well site emissions for 6 months while capturing and disposing of over 90% of pollutants released during hydraulic fracturing. Since the DJ basin has been in production for over a century, depletion problems occur frequently. Old wells impose depleting pressures and overall hydrocarbon migration needed for an economically produced well. Formations throughout this region are also very commonly faulted due to active tectonic history.

Following the coronavirus pandemic and the crude price crash— production in the Denver basin has come to a near stop. Rig activity dropped to just three in June and July of 2020 from 25 just three months prior. Production in the basin fell to 400,000 BPD in June and recovered to 575,000 BPD in just three months. If the rig count remains, BOPD will undoubtedly become downward trending. Gas production has not seen the plummet that crude has, however it is expected to drop below 2 BCFD by August 2021. The primary producing plays in the basin are the Dakota group (D and J sandstones) and the Deep Gas Wattenberg Play (J sandstone). 90 percent of the 800 MMBO and the 1.2 TCFG came from J sandstone. Each play consists of nearly a couple hundred accumulations with at least 1 MMBO. Wattenberg gas field is estimated at 7.8 BCFG The largest oil field is Adena that has an estimated recoverable 63 MMBO. The Pierre shale sandstones play in Spindle Field has an estimated 60 MMBO of ultimate recoverable from the Sussex and Shannon sandstones.

References

Clayton, J. L., and P. J. Swetland. “Petroleum Generation and Migration in Denver Basin.” AAPG Bulletin, GeoScienceWorld, 1 Oct. 1980, pubs.geoscienceworld.org

“GEOLOGY OF THE SUSSEX SANDSTONE.” U. S. GEOLOGICAL SURVEY DIGITAL DATA SERIES DDS-33, 2010, pubs.usgs.gov

Higley, Debra K, et al. “DENVER BASIN PROVINCE .” 2009, doi:https://certmapper.cr.usgs.gov

Higley, Debra K., and Dave O. Cox. “Oil and Gas Exploration and Development along the Front Range in the Denver Basin of Colorado, Nebraska, and Wyoming.” U.S. Geological Survey , U.S. Geological Survey Digital Data Series, 2007, pubs.usgs.gov.

Krieg, Derek, director. Denver-Julesberg (DJ) Basin. Youtube, 5 Sept. 2018, oilfieldbasics.com

“Online Journal for E&P Geoscientists.” Datapages, Inc., 2015, www.searchanddiscovery.com

Weimer, Robert J. “Sequence Stratigraphy and Paleotectonics, Denver Basin Area of Lower Cretaceous Foreland Basin.” Springer Book Archive, Dordecht Springer, 1990, doi.org

Weimer, Robert J. “Stratigraphy and Petroleum Potential of Dakota Group (Cretaceous), Western Denver Basin, Colorado.” AAPG Bulletin, GeoScienceWorld, 1 Mar. 1971, pubs.geoscienceworld.org

This page is currently being authored by a student at the University of Oklahoma. This page will be complete by May 12, 2021