The Niobrara is a significant, self-sourced resource play throughout the Rocky Mountain region. New technologies for horizontal drilling and multistage hydraulic fracture stimulation are unlocking reserves that previously were unobtainable.
Known production comes from both fracture and matrix porosity systems (dual porosity). High matrix porosity is present in the shallow biogenic gas accumulations of eastern Colorado and western Kansas, which is important for natural gas production at burial depths of less than 3,500 ft. The deeper Niobrara thermogenic accumulations generally occur at burial depths greater than 7,000 ft. Burial diagenesis (chemical and mechanical compaction and cementation) reduces porosities to values less than 10% in the deeper parts of the various basins where the Niobrara is prospective. Mature Niobrara source rocks are in these areas of low porosity. Natural fractures are important contributors to production in the deeper areas.
The Niobrara Petroleum System contains the aspects of a large resource play (e.g., widespread mature source and reservoir rocks, self-sourced). The Niobrara was deposited in the Western Interior Cretaceous (WIC) Basin and is a widespread unit in the Rocky Mountain region. The WIC Basin was broken into numerous smaller basins during the Laramide orogeny.
The Niobrara contains reservoir rocks, rich source beds, and abundant seals. The various productive lithologies all have low porosity and permeability. Total organic carbon (TOC) values in shales locally range from 2% to 8% in the eastern WIC area and are reduced to 1% to 3% because of siliciclastic dilution in the western WIC area. Laramide structural events exert the primary control on fracturing within the Niobrara as well as thermal maturity. Neogene extension fracturing also is thought to be an important component for locating production “sweet spots.” Understanding the thermal maturity of the source rocks will help to predict the distribution of hydrocarbon accumulations. Hydrocarbon generation could enhance the tectonic fractures and also could create new ones as a result of overpressuring associated with this process.
Factors thought to be important for Niobrara production in the Rocky Mountain region are: presence of favorable reservoir facies (brittle chalk) and a diagenetic history that enables open fracture systems to exist; presence of mature source rocks to enable a continuous oil column to exist in the trap; source rocks interbedded with respect to the reservoir limestone (chalk); and a favorable tectonic history for fracture formation. Most fracture systems fall into two major categories: structure-related fractures and regional orthogonal fractures.
Resistivity mapping can be used to determine both the presence of a hydrocarbon accumulation and the maturity of source rocks for the Niobrara. The presence of oil in open fracture systems is thought to be the cause of the high resistivity anomalies in chalk beds. A relationship between increasing resistivity of source shales with increasing thermal maturity also has been demonstrated.
Knowledge of the distribution and occurrence of hydrocarbon source and reservoir rocks in the Niobrara interval will greatly aid future exploration.
Regional Setting
The Upper Cretaceous Niobrara (Coniacian-Campanian: approximately 82 million to 89.5 million years ago) was deposited in a foreland basin setting in the WIC Seaway of North America during a time of a major marine transgression. This major transgression probably represents the maximum sea level highstand during the Cretaceous and could contain the best source rocks in the Cretaceous. Present-day basins in the Rocky Mountain region formed during the Late Cretaceous to Early Tertiary Laramide orogeny.
The WIC Basin was an asymmetric foreland basin with the thickest strata being deposited along the western margin of the basin. It is a complex foreland basin that developed between mid to late Jurassic to Late Cretaceous time. The basin was bordered by mountainous areas to the west (zone of plutonism, volcanism, and thrusting that formed the Cordilleran thrust belt) and a broad stable cratonic zone to the east. The foreland basin subsided in response to thrust and synorogenic sediment loading and pulses of rapid subduction and shallow mantle flow.
During sea level highstands, coccolith-rich and planktonic foraminifera-rich carbonate sediments (chalks) accumulated on the eastern half of the seaway. Chalky beds extend into Montana and southern Canada (where they are called the White Spec zones) and into the Gulf Coast region (Austin Chalk). Chalk-rich carbonate facies change westward into siliciclastic-rich beds.
Stratigraphy, Depositional Setting
The Niobrara represents one of the two most widespread marine invasions and the last great carbonate-producing episode of the WIC Basin (the first widespread event is represented by the Greenhorn chalks). Dominant lithologies of the Niobrara Formation are limestones (chalks) and interbedded calcareous shales. The chalk-shale cycles are interpreted to represent changes from normal to brackish water salinities possibly related to regional paleoclimatic factors or sealevel fluctuations.
Chalk lithologies are thought to represent deposition in normal to near-normal marine salinities having a well-mixed water column and well-oxygenated bottom waters. The chalks reflect an influx of warm Gulfian currents into the WIC Seaway during relatively high sea levels. The interbedded shale cycles are interpreted to be caused by an increase in freshwater runoff caused by increased rainfall which could be related to climatic warming. The freshwater runoff creates a brackish water cap and salinity stratification. Vertical mixing of the water column is inhibited, causing anoxic conditions in the bottom waters which enhances preservation of organic material and results in organic-rich source rocks. Decrease in water salinities also is suggested by oxygen isotopic values. The shalier intervals could reflect lower sea levels and greater influx of clastic material from the west. The chalks previously have been interpreted to represent higher sea levels during Niobrara time.
Three major facies are present in the Niobrara and equivalents across the Rocky Mountain region. On the western side of the area, a sandstone facies is present which changes laterally to the east into a calcareous shale facies. This, in turn, changes eastward into a limestone and chalk facies. These various lithologies interfinger and facies changes are very gradational. The Niobrara name is used for chalk and shale units located on the eastern side of the WIC Seaway; whereas, the term Mancos generally is used for the equivalent shale and siltstone units in the western part of the area. The equivalent shoreline and non-marine sandstone units further to the west are known by a variety of names.
The limestone facies is composed of coccolith-rich fecal pellets probably derived from pelagic copepods, inoceramid and oyster shell fragments, planktonic foraminifer tests, micrite, clay, and quartz silt. The thick siltstone facies was derived from highlands to the west. The shales found in the Mancos/Niobrara are dark-gray to black and generally are organic rich (>1% TOC). The shales are fair to excellent source rocks and also provide seals for the chalky and sandy reservoir facies. TOC content in the interval increases to the east.
The chalks of the Niobrara are rich in organic matter and organic-related material (e.g., pyrite). On the east side of the WIC Basin, the Niobrara consists of four chalk beds and three shale intervals. The basal chalk bed is known as the Fort Hays limestone member, and the unit contains some of the purest chalk in the WIC Basin. The Fort Hays is regionally extensive and ranges in thickness from 50 ft in southeast Colorado to 120 ft in New Mexico, to less than 10 ft in southeast Wyoming. Carbonate content persists from the Denver Basin to southwest Colorado into the Laramie, North Park, South Park, and Sand Wash basins. The Fort Hays interval is difficult to distinguish from the remainder of the Niobrara north of the Laramie Basin.
The Fort Hays is overlain by the Smoky Hill member, which consists of organic-rich shales to chalky shale (marls), to massive chalk beds. The interval has been subdivided by various authors into several units.
The Niobrara ranges in thickness from 100 to 300 ft along the eastern side of the WIC Basin to more than 1,500 ft on the west side of the basin. An isopach map illustrates the Niobrara across the northern Rockies region. Thinning occurs in a northeast trend across the map area. This thin trend was related to paleotectonic movement on the Transcontinental Arch. Superimposed on the Transcontinental Arch are northeast axes of thinning. Thinning in the Niobrara is believed to result from differing rates of sedimentation (i.e., convergence or divergence of section) and unconformities at the base, within, and at the top of the formation.
Niobrara deposition in the WIC Basin was influenced strongly by the interplay of warm north-flowing currents from the paleo-Gulf of Mexico and cooler southward-flowing currents from the Arctic region along with sea level fluctuations. Warm waters from the Gulf brought in rich carbonate flora of coccoliths and promoted carbonate production and deposition. Siliciclastic input from the west and cooler Arctic currents inhibited carbonate production and deposition.
Chalks and marls are abundant in the Denver Basin. The section changes to marl and is shalier west of the Front Range and north of the Hartville Uplift. Chalk intervals extend into the Laramie, Hanna, North Park, Sand Wash, and Piceance basins. The section in the Piceance consists of interbedded sandstone, siltstone, and shale. In the San Juan Basin, the Niobrara consists of a mixture of siliciclastic and marl lithologies.
The Niobrara is overlain by the Pierre Shale in the eastern part of the WIC Basin and its age-equivalent Mancos Shale in the western part. The Niobrara overlies the Carlile Formation across much of the WIC Basin and its members – the Codell sandstone, Sage Breaks Shale, etc. The Sharon Springs member of the Pierre Shale overlies the Niobrara in most of eastern Colorado and is an excellent source rock with TOCs ranging from 2% to 8%. The type locality for the Niobrara Chalk is Knox County in northeastern Nebraska.
Source Rocks
Several workers have discussed the organic-rich nature of the Niobrara Formation and the increased thermal maturity and resistivity with increased burial depth. Vitrinite reflectance and resistivity of the organic-rich shale increases with increasing thermal maturity. These values can be mapped to show areas of source rock maturity.
The Niobrara Formation has been analyzed using the Rock-Eval instrument by several workers. Organic-rich beds in the formation have an average 3.2% TOC value. A plot of hydrogen index versus oxygen index (modified van Krevelen diagram) illustrates the type and level of maturity of the source rocks for different depths across the Denver Basin. The plot also illustrates that the kerogen present in the Niobrara is Type II or oil prone (sapropelic).
The Niobrara section was analyzed in the Berthoud Field (Denver Basin) by scientists with the US Geological Survey (USGS). TOC content in the shales ranges from less than 1% to approximately 6%. The organic-rich shales generally are highly radioactive and thus are easy to recognize with gamma ray logs. Gamma ray values increase as a function of increasing TOC. The organic carbon tends to attract or be deposited with uranium which accounts for the high gamma radiation. TOC content in the Niobrara Formation is proportional to the amount of acid-insoluble residue.
The Niobrara produces self-sourced oil and gas from tight (low porosity and permeability), fractured carbonate reservoirs. Niobrara source rocks are dominantly Type II, oil-prone kerogen. The richest source rocks are in the Denver Basin where the TOC content reaches 8%. In south-central Wyoming, the TOC content averages 2.1%. The 700-ft Niobrara section in northwest Colorado has good source rock potential. Source rocks in southwestern Wyoming are dominantly Type II with some mixing from Type III, gas-prone kerogen. The average TOC content from samples in southwest Wyoming is 1.85%.
Hydrocarbon generation starts at vitrinite reflectance values of 0.7% and began approximately 76 Ma in the Piceance/Uinta Basin areas. Hydrocarbon generation is estimated to have started approximately 72 Ma in southwest Wyoming. Hydrocarbon generation in the Denver Basin started in the Late Cretaceous.
Reservoir Rocks
The lithology of the Niobrara changes from east to west across the WIC Basin. In the Denver Basin, the lithology consists of interbedded calcareous shale, shaley limestones, marls, and limestones. Westward, the lithology becomes shalier and sandier. The carbonates still are present in the western area, but clastics begin to dominate.
Most Niobrara reservoir rocks have undergone mechanical and chemical compaction and are low-porosity and low-permeability rocks. Burial depth is the single most important factor affecting porosity in the Niobrara. Chalks have high original porosities (50% or greater). Initial dewatering and mechanical compaction is the first diagenetic phase. Grain and fossil breakage and reorientation reduce porosity. Initial coccolith grain sizes are 0.2 to 1 micron. Chemical compaction is characterized by calcite dissolution along wispy dissolution seams, microstylolites, and stylolites. Grain-to-grain dissolution along microstylolites is common and the dissolved calcite is reprecipitated locally.
A plot illustrates density log porosity versus depth for the chalks in the Denver Basin. The chalks have an average porosity of 6% at 7,000 ft. It appears that the porosity trend flattens with burial depth. Both shallow and deeply buried chalks have low permeabilities. Initial average pore throat sizes are a few tenths of a micron, which are further reduced with diagenesis. Fracturing is an important aspect for reservoir performance.
Mechanical Stratigraphy, Fractures
The generalized mechanical stratigraphy for the Niobrara shows chalk beds behave in a brittle fashion and are susceptible to fracturing; whereas, the marl or calcareous shales behave in a ductile manner and contain fewer fractures. Chalk beds are the target of horizontal drilling.
Fractures can be created in a number of ways, including folding related to basement or listric faulting or solution of evaporates, high fluid pressures associated with hydrocarbon generation, regional stress fields (regional fractures), regional uplift and stress relief, or a combination.
Major fracture zones in the Austin Chalk can be mapped into four major categories:
- Anticlinal folds.
- Monoclinal flexures.
- Listric normal faults.
- Graben-in-graben normal faults.
A good understanding of orientation of fracture sets relative to local and regional structure has been developed. In addition, the size of the fracture halo (zone) adjacent to faults and folds is understood. These models could prove to be important for the Niobrara Formation in the Rocky Mountain region. The Silo Field fracture system, for example, fits into the monoclinal flexure model.
Fracturing often is associated with Laramide-age structures; however, they often are filled with calcite which results in poor production. Neogene-age extensional fracturing and/or microfracturing appear to enhance production. Fractures from productive fields generally are lined with calcite but are not cemented completely.
Resistivity anomalies have been observed in the fractured limestone reservoirs in the Silo Field and can be mapped by maximum resistivity (isoresistivity) and thickness of resistive bed. In the Silo Field area, both methods illustrate a northwest-trending anomaly that coincides with known production. Maximum resistivities for the productive chalk interval range from less than 20 ohm-m to greater than 100 ohm-m. Productive wells generally have maximum resistivities greater than 40 ohm-m. The thickness of resistivity (greater than 15 ohm-m) in the productive chalk zones is approximately 40 ft.
The high resistivity can best be explained by fractures filled with oil giving the anomaly; however, other factors could contribute, including calcite-filled fractures or increased local cementation related to faulting and fracturing. Resistivities diminish (using both methods) in all directions away from Silo Field, illustrating that the increase in resistivity is not simply a depth-related compaction-cementation phenomena. Regardless, there appears to be a mappable anomaly that coincides with production. Reservoir resistivity methods can be used to suggest where accumulations exist, but do not help predict the intensity of fracturing necessary for economic production. The resistivity anomaly might be caused by fractures filled with oil, but whether sufficient fractures are present to produce economic quantities of oil is another matter. This method should be used in conjunction with other information, such as structural mapping, to help predict where accumulations exist and also are sufficiently fractured to be productive.
Petroleum System Events Chart
A generalized petroleum system events chart for the Niobrara shows the Niobrara is self-sourced and also has reservoir rock potential in the chalkier intervals. These intervals tend to be more brittle. This also is where fractures have been noted in cores.
Traps are formed during the Laramide orogeny and enhanced by later extension. Niobrara source rocks reached thermal maturity beginning in Late Cretaceous. Migration of oil from source rocks into reservoirs began in Late Cretaceous and continued into the Neogene. Burial history reconstructions are an important aspect for determining the type of hydrocarbons (oil or gas) expected at different depths in the Rockies basins.
Hydrocarbon Production
Niobrara production represents some of the oldest established production in the Rocky Mountain region. The oldest field in the region is the Florence-Cañon City Field which was discovered in 1881. The field produces from the Pierre Shale immediately above the Niobrara and is believed to be sourced from the Niobrara and Sharon Springs. The Boulder oil field (western Denver Basin) was discovered in 1901 and also is productive from the fractured Pierre Shale but also sourced from the Niobrara. Fractured Mancos Shale production was found in Rangely in northwest Colorado in 1902. Niobrara production was established in Tow Creek in the Sand Wash Basin in 1924. The Berthoud Field of the western Denver Basin was discovered in 1927 and is productive from several horizons including the Niobrara. Gas in the Niobrara was discovered in Beecher Island in eastern Colorado in 1919; however, commerciality was not established until 1972. The Niobrara interval is productive in the Bowdoin Field of Montana which was discovered in 1913. The reason for these early discoveries is that many of them are associated with surface structures which were the primary targets of early explorers.
Hydrocarbon production comes from all three major Niobrara lithofacies:
- Microporous and fractured coccolith-rich and planktonic foraminifer-rich limestone (eastern part of the WIC Basin).
- Fractured marls and shales (mainly in the central part of the seaway).
- Fractured sandstone-rich and siltstone-rich facies, mainly in the western and southwestern parts of the seaway.
Production occurs in the Laramide-aged Powder River, Denver, North Park, Greater Green River (including Sand Wash), Raton, San Juan, and Piceance basins and in north-central Montana. The widespread distribution of production along with many wells with hydrocarbon shows across these basins suggests a large resource play might exist. The majority of recent drilling activity in the Niobrara has been in the Denver Basin, north of Wattenberg Field and in southeast Wyoming near Silo Field.
Hydrocarbon production from chalk reservoirs occurs along the shallow eastern margin of the Denver Basin. Many of the gas accumulations in this area occur in structural traps. Reservoirs require hydraulic fracture stimulation. The gas is biogenic or microbial in origin. Production in the shallow play comes from the upper chalk bench or Beecher Island member of the Niobrara and mainly is from microporosity within the chalks, but is enhanced by natural fracturing. Production from the shallow Niobrara from eastern Colorado is 600 Bcf of gas. Beecher Island Field is one of the first and largest fields discovered in the shallow Niobrara. Commercial production dates back to 1972 – the initial discovery was in 1919 – and the cumulative for the field is 100 Bcf of gas. Three-D seismic data have been used effectively to improve development and exploration success ratios in fields.
Shallow gas production from the Niobrara also occurs in north-central Montana. Bowdoin Dome has produced 62 Bcf of gas and 19,000 bbl of oil from the Niobrara. Additional Niobrara fields are to the west of the Alberta Basin which extends into Montana. The largest field to date is the St. Joe Road Field which was discovered in 2001 and has produced 18.2 Bcf of gas.
Deeper in the Denver Basin, the Niobrara is oil productive in a number of fields. The porosity of the chalks in the deeper part of the basin has been reduced dramatically by compaction and burial diagenesis. Production is attributed to the presence of fractures in the chalky intervals. Some attempts have been made to establish production from some of the rich, shaley intervals within the Niobrara. The shale gas and fractured chalk potential of the deep Denver Basin area is significant, as shown by fields like Wattenberg and Silo. Silo Field was discovered in 1981 and has produced approximately 10.4 MMbbl of oil and 8.9 Bcf of gas.
The Niobrara is productive on the Casper Arch of Wyoming at Salt Creek and Teapot fields. Total production has been 1.5 MMbbl of oil and 0.2 Bcf of gas. In the deeper Powder River Basin, production has been established in a number of accumulations including Fetter, Hilight, Brooks Draw, and Flat Top. Hilight has produced 411,000 bbl of oil and 0.8 Bcf of gas to date.
The western portion of the region is productive in a variety of traps and lithologies (mainly siliciclastic), and there is significant potential for hydrocarbon production in many of the western basins. The basal part of the Niobrara equivalent in the west yields oil and gas in the San Juan Basin from a sandstone and shale interval (Tocito and Gallup sandstones). Examples of producing fields from the Gallup are Bisti and Verde fields. Bisti Field has produced 41.8 MMbbl of oil and 79.2 Bcf of gas. Verde Field has produced 8.1 MMbbl of oil and 2.5 Bcf of gas. Examples of fields producing from the Tocito sandstone are the Blanco South and Chipeta fields. These fields have produced 4.2 MMbbl of oil and 18.8 Bcf of gas. Production is from interparticle porosity but is enhanced by fractures.
The upper Niobrara equivalent (Smoky Hill member) is productive in the Sand Wash Basin from fractured reservoirs, and perforated intervals are commonly long. Field examples are Buck Peak and Tow Creek. Buck Peak has produced 4.8 MMbbl of oil and 8.5 Bcf of gas. Tow Creek has produced 3 MMbbl of oil and 0.3 Bcf of gas. Farther to the west where the Niobrara equivalents are dominantly shale, production is found in the Rangely and Douglas Creek Arch fields. Production from the fractured Mancos Shale at Rangely represents some of the oldest production in Colorado (since 1902). The Mancos at Rangely has produced approximately 11.9 MMbbl of oil and 0.2 Bcf of gas. Neogene-age extensional faulting is key to production at Buck Peak and Rangely. Douglas Creek Arch production comes mainly from Cathedral Field. The field has produced 56.5 Bcf of gas and 40,600 bbl of oil from the Mancos (mainly the Mancos B zone).
Other production equivalent to the upper Niobrara zone comes from the Mancos interval in the San Juan Basin. Examples of Mancos producing fields include East Puerto Chiquito, West Puerto Chiquito, Rio Puerco, Gavilan, Basin, and Boulder. These fields are interpreted to be fractured reservoirs, and producing intervals are hundreds of feet thick. The Puerto Chiquito fields have produced 19.3 MMbbl of oil and 55.5 Bcf of gas. Gavilan Field has produced 7.8 MMbbl of oil and 111 Bcf of gas. Boulder Field has produced 1.8 MMbbl of oil and 1.6 Bcf of gas. Basin Field has produced 120,000 bbl of oil and 4.1 Bcf of gas. Rio Puerco Field has produced 1.3 MMbbl of oil and 1.4 Tcf of gas.
The Mancos is gas productive in the deeper parts of the Uinta Basin in several fields including Natural Buttes. Mancos also is productive in some silty and very fine-grained sandstone zones in the Cathedral Field of the Douglas Creek Arch. New Mancos/Niobrara production has been established in several areas of the deeper Piceance Basin (e.g., Mamm Creek Field).
Resource Estimates
The USGS has estimated recoverable resources from the Mancos/Niobrara for the following basins in the Rocky Mountain region:
- Greater Green River Basin: 103.6 MMbbl of oil, 62 Bcf of gas;
- Piceance Basin: Mancos/Mowry combined for 1.6 Tcf of gas;
- Uinta Basin: Mancos/Mowry combined for 3.1 Tcf of gas;
- Powder River Basin: Niobrara Formation for 520 MMbbl of oil, 0.95 Tcf of gas;
- Denver Basin: Niobrara/Codell for 39,800 bbl of oil, 328 Bcf of gas;
- Niobrara Biogenic Chalk: 984 Bcf of gas;
- San Juan Basin-Mancos Continuous: 5.1 Tcf of gas; and
- Hanna-Shirley-Laramie: 38 MMbbl of oil, 19 Bcf of gas.
The resource assessments illustrate the significant potential of the Niobrara across the Rockies, not only for thermogenic accumulations of oil and gas, but also biogenic accumulations.
Niobrara Petroleum System in the Denver Basin
The Denver Basin is the current focus of most Niobrara drilling in the Rocky Mountain region. The Denver Basin was created by the Laramide orogeny and is one of the largest sedimentary basins in the region. The basin is asymmetric with a gentle east flank and a faulted to very steeply dipping west flank. Source rock intervals for the Cretaceous include the Skull Creek, Graneros, Carlile, Niobrara, and lower Pierre (Sharon Springs) shales. Most production in the basin comes from Cretaceous D and J sandstones. In the Wattenberg Field, production comes from the Dakota, J, D, Greenhorn, Codell, Niobrara, Hygiene, and Terry units. The Wattenberg area is a geothermal “hot spot.” The principal reason for all the stacked pays in Wattenberg is the temperature anomaly.
The Niobrara Petroleum System consists of source beds and reservoir units in the Niobrara, but also the overlying Cretaceous Hygiene sandstones (Terry and Hygiene). Thermogenic oil and gas accumulations occur in the deeper part of the Denver Basin, while shallow biogenic accumulations of gas occur on the shallow east flank. Niobrara production turns to oil as the geothermal gradients decrease in all directions away from the Wattenberg area. An important aspect of the Niobrara Petroleum System is that it sources Upper Cretaceous reservoirs in the Denver (e.g., Terry and Hygiene) and Powder River (e.g., Parkman, Sussex, Shannon, and Teapot) basins.
New discoveries in the Niobrara in the Denver Basin include the Hereford Field area, northeast of Wattenberg. The field is being developed with horizontal drilling and multistage hydraulic fracture stimulations. The Hereford area is one of several areas that currently are being developed in the Denver Basin. The Silo Field area also is getting new horizontal wells.
Exploration Methods
Exploration for fractured Niobrara reservoirs should incorporate many if not all of these methods: seismic acquisition, aeromagnetics study, surface lineament analysis, subsurface mapping, isoresistivity mapping, logging technology, and technology to produce the reservoir. Two-D and 3-D seismic are extremely important to map structural anomalies. Three-D, three-component (compressional and shear wave data) methods also have proved to be effective in analyzing the fractured reservoir.
Aeromagnetics is a tool that can identify basement shear zones’ areas of potential fractures having gradient changes such as narrow zones of steep gradients. Aeromagnetic data examined in the Silo Field area illustrate possible northwest-trending shear zones. If basement fracture systems propagate all the way to the surface, then a surface lineament analysis also might be effective. Northwest-trending surface lineaments in the Silo area have been mapped by use of remote sensing techniques.
Resistivity mapping is important to show areas of oil accumulation. When resistivity mapping is combined with subsurface mapping, the most probable areas of fracturing can be predicted. Geophysical logs such as the FMS, FMI, and CAST logs are logging technologies that identify fractured reservoirs. Horizontal drilling and multistage hydraulic fracturing offer technologies to economically produce hydrocarbons from the reservoir.
An understanding of the regional stress field is important in most tight oil and gas plays. The direction of maximum horizontal stress (Shmax) generally is the direction of open fractures. Regional horizontal stress maps have been published for North America. Present-day stress fields reflect Neogene extensional tectonics and the epeirogenic uplift that has taken place in the Western US.
Regional epeirogenic uplift of western North America and subsequent erosion (denudation) might play a role in Niobrara microfractures. Overburden removal results in lowered effective stress in rocks that also might be overpressured. This mechanism could be important in all tight reservoir plays in the Rocky Mountain region.
Widespread source and reservoir rocks make the Niobrara Formation an attractive target for exploration across the Rocky Mountain region. The Niobrara contains mature source rocks interbedded with brittle limestones (chalks) in the deeper parts of many basins. Thermogenic production occurs from chalk intervals in the eastern part of the region and from siliciclastics and shales in the western and southwestern parts of the Uinta and San Juan basins. Biogenic gas production occurs at shallow depths along the eastern Rocky Mountain region in Colorado, Kansas, and Nebraska. Generally, production comes from depths less than 3,500 ft. Shallow gas production also occurs in several areas of north-central Montana and generally is structurally controlled.
Niobrara reservoirs generally have low permeabilities, so natural fracturing plays a role in economic production. Limestone (chalk) beds behave in a brittle manner; whereas, the adjacent calcareous shales often behave in a ductile manner. Fractures occur for a variety of reasons and several models can be used for exploration. Early created fractures are susceptible to extreme diagenesis and generally are cemented completely. Late-stage structural movement can help to reopen old fractures or create new ones in the Niobrara.
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