The Piceance Basin is an intracratonic basin that spans across an area of 5,500 square miles in the northwestern region of Colorado. Situated in the Uinta-Piceance Province of Colorado and Utah, the Piceance is the second-largest natural gas basin in the United States behind the Marcellus Shale. As shown in Figure 1, the Uinta-Piceance Province is comprised of five primary petroleum systems, which are given in ascending stratigraphic order as follows: Phosphoria, Mancos/Lowry, Ferron/Wasatch Plateau, Mesaverde, and Green River. Given their previous development as well as their future potential, the Mancos/Lowry, Mesaverde, and Green River have received the most attention.
History of the basin
As shown in Figure 2, the Piceance is situated in northwestern Colorado, with the Douglas Creek Arch separating it from the Uinta Basin of Utah. Initially located in a foreland basin along the Western Interior Seaway, the Piceance Basin area received clastic sedimentary deposits from the Sevier thrust belt during the Cretaceous Period. The Piceance Basin subsequently assumed its current structure during the Late Cretaceous-Eocene Laramide orogeny. As a result of this significant mountain-building event, the Piceance Basin exhibits a highly asymmetric shape, with stark differences between the western and eastern boundaries. The western boundary consists partially of the Douglas Creek arch, which is a faulted anticline that bifurcates the Uinta-Piceance Province into the Uinta Basin of northeastern Utah and the Piceance Basin of northwestern Colorado. Together with the Uncompahgre uplift, the Douglas Creek arch forms a gently sloping western bound to the Piceance Basin. In contrast, the steeply sloped White River uplift constitutes the eastern boundary of the basin. Figure 3 highlights the asymmetric shape of the basin, as well as the features of the western and eastern boundaries.
During the early 1900s, exploration for oil in the Piceance Basin first took place near surface structures such as the Rangely Anticline, DeBeque Anticline, and White River Dome. In the 1920s, the focus of exploration largely shifted to the Wasatch at the Piceance Creek Dome as well the Mesaverde Group at the Divide Creek Anticline. However, the Piceance Basin did not rise to any sort of eminence until the 1940s with the development of the Weber oil resource at Rangely Field. Over the next seven decades, the Rangely Field in the northwestern region of the basin produced over 850 million barrels of oil, with most of the production coming from the Pennsylvanian- to Permian-age Weber Sandstone. In addition, the Eocene Green River Formation contains an estimated 1 trillion barrels of oil-shale deposits.
Notwithstanding its significant oil deposits, the Piceance Basin is now most known for its natural gas resources. Since the discovery of gas in Tertiary reservoirs during the 1890s, the region has blossomed into a significant producer of natural gas. Following the development of smaller conventional gas fields in the Eocene Wasatch and Green River formations, activity in the Mesaverde basin-centered gas play thrust the Piceance Basin onto the national stage of natural gas production in the early 2000s. Largely through the development of unconventional tight-gas reservoirs within the Upper Cretaceous Mesaverde Group, gas production in the Piceance reached a peak level of 2.02 Bcf/d in 2014.
Geological risks and uncertainties
The key geological considerations in the Piceance Basin include the hydrocarbon charge (that is, source and maturation), as well as reservoir facies, geometry, and quality. Relatedly, trap closure and trap seal are regionally unpredictable given that the majority of hydrocarbons in the basin are not contained within distinct structural traps.
For the Cretaceous Mesaverde Group in particular, one of the key considerations is reservoir size. The Mesaverde is composed of the Iles and Williams Fork formations, with the latter containing most of the gas potential. Having been deposited as point bars by meandering streams, the Williams Fork sandstone reservoirs are relatively small (500-800 ft. lateral extents). However, given a widespread distribution of gas, hydrocarbon charge is not considered to be a significant geologic risk in the Mesaverde Group. Similarly, the timing of gas generation does not present a meaningful risk either, given that exploration wells have found substantial gas-charged intervals around the axis of the basin.
Within the Mancos/Lowry, there is uncertainty as to whether certain reservoirs (the Morrison, Cedar Mountain, and Dakota) contain conventional or unconventional accumulations of oil and gas. Notably, the gas-water contacts contacts in these reservoirs are largely unknown or nonexistent.
As for the Green River Formation, thermal maturity appears to be a key issue. With an estimated 1.2 trillion barrels of oil in place, the Green River contains one of the world’s largest oil-shale deposits. Yet the majority of these deposits in the Piceance were not buried to sufficient depths to achieve the thermal maturity necessary for significant hydrocarbon generation.
Exceeding 7,000 ft. in some places, the Mesaverde Group is a thick interval characterized by an overall regression of facies, as exhibited by Figure 4. Near the base, the interval consists of marine sandstones and shales, while fluvial sandstones and conglomerates occupy the top section. Notwithstanding their wide distribution, the reservoirs are discontinuous and low-quality, with a porosity of 2-10% and a permeability of 0.1 md – 0.1 µd. Furthermore, reservoir quality is inversely related to depth, with the poorest reservoirs located in older sections near the axis of the basin.
Within the Mancos/Mowry system, the Mancos B Sandstone is one of the more prominent intervals. Composed of interbedded sandstone and laminated mudrock with a thickness of 500-1,000 ft., the Mancos B was formed on a depositional ramp during the Santonian and early Campanian. In addition, the formation exhibits a range of porosities from 1-11% as well as an average permeability of 0.7 md.  As for the Green River Formation, oil and gas is primarily produced from marginal-lacustrine rocks. The notable Douglas Creek Member of the Green River Formation is composed of litharenite reservoirs with porosities ranging from 11-15%.
Trap and seal
In general, the Mesaverde Group of the Piceance Basin is characterized by relatively few large structural closures. As a result, structural considerations do not heavily influence the distribution of gas at this level. In terms of seals, the shale-prone section of the Wasatch Formation provides a top seal for the conglomerate reservoirs in the upper portion of the Mesaverde. Similarly, the 3,000 – 5,000 ft. thick Mancos Shale functions as a bottom seal, an outcropping of which is shown in Figure 5. Within the Mancos/Lowry itself, the traps are largely continuous, but there are a few intermingled conventional traps such as the high-angle reverse fault at the Hells Hole field. Finally, the Douglas Creek Member of the Green River Formation contains structural and structural-stratigraphic traps, with enclosing shale, mudstone, and siltstone functioning as seals.
Source and migration
Overall, the Mesaverde Group boasts a plethora of rich, mature, gas-prone source rocks. More specifically, the group is comprised of three primary source facies, including the marine shales of the Mancos and Iles formations, the coals of the Iles and Williams Fork formations, and the nonmarine shales of the Iles and Williams Fork formations. Both vertical migration through fractures and lateral migration through continuous channel sandstones and marine shoreface sandstones have occurred within the Mesaverde. As for the Mancos/Lowry, the source rocks primarily consist of the enclosing Cretaceous marine shale, with reported total organic carbon (TOC) levels ranging from 1-4%. Unlike many of the other systems in the Piceance, the Douglas Creek Member of the Green River Formation contains mostly thermally immature source rocks. The gas within the Tertiary reservoirs likely migrated vertically from the gas-prone source beds of the Upper Cretaceous Mesaverde Group.
Future petroleum potential
The greatest potential for future production lies within the Piceance Basin’s natural gas deposits. According to a 2016 report from the U.S. Geological Survey (USGS), the Mancos Shale formation holds approximately 66.3 trillion cubic feet of natural gas, a momentous increase over the 1.6 trillion cubic feet estimated by the USGS report in 2003. In addition, the Mesaverde Group contains an estimated 13.1 trillion cubic feet of undiscovered continuous natural gas. These updated figures portray the Piceance as the second-largest natural gas basin in the United States behind the Marcellus Shale, which contains an estimated 84 trillion cubic feet.
However, with the drop in commodity prices in 2015-2016, a number of public operators eventually exited the Piceance Basin to pursue other U.S. gas plays with more favorable economics. Among these were WPX Energy, Ovintiv, Occidental Petroleum, and ExxonMobil. Given that private companies now drive most of the activity in the Piceance, the development outlook for the basin is largely dependent on breakeven economics. As of March 2021, the largest operator in the Piceance Basin, Terra Energy Partners, produced 710 million cubic feet of natural gas per day from 7,316 wells.
With substantial gas processing and transport infrastructure in place, the Piceance Basin has the potential to compete meaningfully with other gas markets in the United States. However, much of the success is dependent on obtaining access to international liquefied natural gas (LNG) markets through export facilities on the West Coast. Yet efforts to build the Jordan Cove LNG export facility in Oregon have faced regulatory obstacles, resulting in a pause on the project’s development. Similar issues have plagued the Pacific Connector Pipeline, which would be a key element in transporting natural gas from the Piceance Basin to the Jordan Cove facility.
Petroleum and facility engineering aspects
Regarding engineering considerations, effective well spacing and completion technologies are especially important in the Piceance Basin. In the Williams Fork Formations of the Mesaverde Group, optimal well spacing is typically no more than 20 acres, with some fields being developed at 10-acre well spacing due to the highly discontinuous nature of the sandstone reservoirs. In the Douglas Creek Member of the Green River Formation, the Tertiary gas reservoirs are underpressured, leading operators to prefer developing the Mesaverde given its higher per-well recoveries. With the evolution of technology, operators began drilling horizontal wells into the gas-prone deposits of the Mancos Shale Formation in 2008. Despite the use of longer lateral lengths and higher proppant volumes, production rates declined from 2014 to 2018. The disappointing results are attributable to lower formation pressures, higher hydrocarbon viscosities, reservoir properties, and inapt completion techniques. Notably, however, the horizontal wells drilled in the Mancos/Niobrara zones have exhibited low water rates of less than 100 BWPD per well, which translates into lower operating costs relative to other shale gas plays. Viewing the Piceance Basin as a long-term play, some operators have invested in Centralized Water Management Facilities (CWMF), which improve profitability by treating produced water, recovering oil and condensate, and providing water for hydraulic fracturing operations.
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