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A second look at the size of US shale formations is revealing they hold far more natural gas, and pushed a new name up near the top of the list: the Mancos Shale.
A recent reassessment of the formation in western Colorado concluded it holds 66 Tcf of shale gas that could be produced using current technology, making it second only to the prolific Marcellus Formation for unconventional gas in the US.
This elevates the profile of the formation, which the US Geological Survey (USGS) had previously estimated at 1.6 Tcf in 2003. The agency also recently upped its estimate for the Barnett Shale, doubling it to 53 Tcf.
“We reassessed the Mancos Shale in the Piceance Basin as part of a broader effort to reassess priority onshore US continuous oil and gas accumulations,” said Sarah Hawkins, a USGS geologist who was the lead author of the study. “In the last decade, new drilling in the Mancos Shale provided additional geologic data and required a revision of our previous assessment of technically recoverable, undiscovered oil and gas.”
Based on a growing body of data, the USGS is working on assessments of two Texas plays, the Wolfcamp in the Midland Basin, and the Eagle Ford Shale; and one in Colorado, the Niobrara in the Denver Basin.
For those drilling into the Mancos, the USGS evaluation confirms what they have been seeing.
“There has been drilling for the last 20 years and there is decades worth of drilling location left,” said David Ludlam, executive director of the West Slope Colorado Oil and Gas Association, who said the gas potential may well exceed 100 Tcf.
He said operators working there have dozens of successful exploratory wells in shale, but the current gas market does not justify development drilling. The gas sands there are commonly developed using slanted vertical wells from pad sites with multiple wells.
The USGS used data from 2,000 wells drilled since its last evaluation, as well as field work and research core analysis, to divide the formation into units with similar geologic and well production characteristics, Hawkins said. That work led to an estimate of technically recoverable reserves for the Mancos ranging from 34 Tcf to 112 Tcf, with a mean of 66 Tcf.Glowing assessments of the gas in the ground are not fueling the sort of activity that transformed the Marcellus. Recently there were no rigs drilling in the Barnett, and 12 of the 16 wells working in Colorado were in the DJ Basin in the eastern part of the state, according to data by Energent Group, a provider of shale data.
Abstract In early 2013, a study of the Mancos Shale was initiated at Colorado Mesa University with initial funding from the CMU Unconventional Energy Center and industry donations. The goal of this project is to generate a stratigraphically calibrated mineralogical, geochemical, radiometric, and sedimentological dataset for the total Mancos in the southwest Piceance Basin, southern Douglas Creek Arch, and southeast Uinta Basin. The total project area is about 4,185 mi2, extending from Cisco, UT, to Delta, CO. Input comes from four sources:public-domain well-log data; public-domain organic and inorganic geochemical data; spectral gamma-ray, mineralogical, and inorganic geochemical analyses of cuttings from a well about 16 mi north of Fruita, CO; and measured sections from the outcrop belt near Grand Junction, CO. In the project area, the Mancos is 3,697 to 4,751 feet thick (average = 4,059 ft) and is subdivided into four " assessment/inventory" intervals: Upper Mancos, Prairie Canyon, Niobrara, and Lower Mancos. These intervals are clearly defined on well logs and in outcrop, and have average thicknesses of 865, 1,231, 1,656, and 329 feet, respectively. Currently, public-domain data have been harvested from 38 wells in the project area, including 559 total-organic-carbon (TOC), 513 RockEval, 95 vitrinite-reflectance (VR), 175 total-carbonate (TC), 12 x-ray diffraction (XRD for bulk mineralogy), and 596 x-ray fluorescence (XRF) analyses (El Attar, 2013). Most analyses (∼95%) come from the lower Mancos and Niobrara equivalent. New data generated from cuttings in the Fees Federal 2–6–8–101 (API 05–045–07432), include 169 XRD, TC (calcimeter), and spectral gamma-ray (SGR) analyses. These samples span the total Mancos and part of the overlying Mesaverde Group and underlying Dakota Sandstone. Outcrop work includes 16 measured sections (2,245 ft) with foot-by-foot gamma-ray measurements (total count and SGR) for about half of the sections. It is anticipated that when completed, the results will provide a platform that will enhance exploration and exploitation of the Mancos, plus allow researchers to better understand its depositional history, stratigraphy, and sedimentology. Additionally, the inorganic-geochemical data will allow environmental studies on Mancos intervals that could influence disposal of produced water and drill cuttings. Data on mineralogic characteristics will also contribute to a better understanding of the mechanical-stratigraphy of the Mancos, which will aid well completions.
Li, N.. (Black Hills Exploration & Production) | Lolon, E.. (Liberty Oilfield Services) | Mayerhofer, M.. (Liberty Oilfield Services) | Cordts, Y.. (Black Hills Exploration & Production) | White, R.. (Black Hills Exploration & Production) | Childers, A.. (Black Hills Exploration & Production)
Abstract The Mancos-Niobrara formation in western Colorado is estimated by the USGS to contain 66 trillion cubic feet of natural gas. Successfully developing this asset depends on understanding the geology, geomechanics, the impact of fracture length and height, conductivity, fracture spacing, and well spacing on estimated ultimate recovery. The Mancos-Niobrara has tremendous resource potential and is in the early stages of development in the study area. This paper discusses the development and application of a detailed numerical reservoir model to guide best practice development. Six wells drilled from two multi-well pads and hydraulically fractured to produce natural gas are the subject of this paper. This study provides a comprehensive evaluation and integrated approach to help optimize field development in this new emerging play. The reservoir model includes six wells on two pads. The reservoir was characterized using geochemistry, triple-combo logs, dipole-sonic logs, and formation images. Completion geometry and efficiency were evaluated by collecting data including micro-seismic fracture mapping, micro-deformation, mini-fracturing tests, and production logs. Different designs or treatment schedules were utilized during completion operations to provide additional information on the formation sensitivity to differing completion parameters. The numerical reservoir modeling performed in this study gives deference to the rich data collected. The model was used to estimate effective fracture lengths and heights, evaluate well communications, predict individual well performance, and identify areas for economic optimization. Created fracture half-lengths were estimated to be 900-1,000 ft. This result shows excellent agreement between history matching the hydraulic fracture treatment, micro-seismic monitoring, and production results. The reservoir model confirms direct hydraulic connections, modeled as a few high-conductivity pathways (‘pipelines’), crossing multiple wells that could result from the repeated enhancement of the same natural fracture network during different treatment stages. Production results show large performance differences among the wells despite the similarity in completion designs which is attributed to well interference and shared production. Therefore, it would be advantageous in future development―utilizing essentially the same completion technique, double well spacing to 2,700 ft., while still maintaining 75%-80% gas recovery factors over 40 years, and drilling half the number of wells. Production logging indicated that only 30% of perforated clusters were producing a significant amount of gas. The simulation sensitivity shows that significant gas production boost was possible, especially in the first five years, if cluster efficiency was increased. Fracture conductivity was found to be of secondary importance for short and long-term gas recoveries due to the low system permeabilities. Accordingly, the flexibility in diversion techniques and varying proppant size to increase cluster efficiency should be tested. The reservoir modeling also shows that only a portion of the gross formation thickness may be effectively produced implying that the effective fracture height may be less than 750 ft. measured by micro-deformation. This leads to a future opportunity of targeting the more liquids-rich upper Niobrara zones in addition to the lower gas-producing interval.
Abstract The expansion of unconventional petroleum resource exploration and production in the United States has led to an increase in source rock characterization efforts, particularly related to bulk organic and mineralogical properties. To support the analytical and research needs of industry and academia, as well as internal work, the U.S. Geological Survey (USGS) has collected and prepared shale geochemical reference materials (GRMs) from several major shale petroleum systems in the U.S. The sources of these materials are the Late Cretaceous Boquillas (lower Eagle Ford-equivalent) Formation (roadcut near Del Rio, TX), Late Cretaceous Mancos Shale (outcrop near Delta, CO), Devonian–Mississippian Woodford Shale (outcrop near Ardmore, OK), Late Cretaceous Niobrara Formation (quarry near Lyons, CO), Middle Devonian Marcellus Shale (creek bed in LeRoy, NY), and Eocene Mahogany zone oil shale of the Green River Formation (oil shale mine near Rifle, CO). Of particular interest in the development of these GRMs has been the examination of variability between laboratories and specific methods or instruments in commonly made measurements, including major- and trace-element concentrations, X-ray diffraction (XRD) mineralogy, total organic carbon (TOC) content, and programmed pyrolysis (PP) parameters. For the component concentrations and parameters we measured, the techniques and instrument types included: (1) elemental analysis by X-ray fluorescence, inductively coupled plasma mass spectrometry, and instrumental neutron activation analysis; (2) XRD mineralogy with various preparatory methods (spray drying or micronizing with or without internal standard); (3) TOC by combustion with infrared detection after carbonate removal or the PP approach; (4) PP by Rock-Eval 2 or more recently developed instruments (Rock-Eval 6, Source Rock Analyzer or SRA, and Hydrocarbon Analyzer With Kinetics or HAWK). Overall, the results showed that the selected shales cover a wide range of source rock organic and mineralogical properties. Major- and trace-element chemistry results showed low heterogeneity consistent with other USGS GRMs. Comparison of TOC results showed coefficients of variation (COV) of around 5% and the most consistent organic geochemical results between different laboratories and methods. Arguably the most relevant PP measurement, S2 or kerogen hydrocarbon-generating potential (mg-HC/g-rock), showed a somewhat wider range of variability than TOC (COV ~10%), but was consistent between the three modern instruments and the industry-standard Rock-Eval 2. Major phase mineralogy (mineral concentrations ≥10 wt. %, organic-free basis) were comparable between laboratories, but variability in minor phase identification and quantification was observed. Utilization of these shale GRMs as quality control samples and testing materials is expected to help support analytical and experimental efforts in the continued development of unconventional petroleum resources.
A comparative survey of over 30 blanket-geometry tight gas sandstones in 16 sedimentary basins was prepared for the Gas Research Institute. For each stratigraphic unit a uniform set of information was obtained on general attributes, economic factors, geologic parameters of the basin and the formation, reservoir engineering data, and operating conditions. Each tight gas reservoir was considered within a sedimentary framework of associated lithogenetic facies that make up a depositional system.
In contrast to lenticular sandstones, which are primarily fluvial deposits, blanket-geometry tight gas sandstones were deposited as deltaic, barrier strandplain, and shelf systems. The reservoir geometry resulting from the deposition of blanket sandstones is expected to mitigate selected reservoir engineering problems associated with tight gas sand development. Results of this survey are being utilized in a more detailed study, now underway, which will ultimately lead to the selection of two prospective field test areas, possibly consisting of individual stratigraphic units, geologic basins, or depositional systems.
The Gas Research Institute (GRI) has designated as one of its goals the increased understanding and ultimate utilization of unconventional gas resources. One such resource is gas contained within low-permeability, or tight, sand reservoirs. Estimates of maximum recoverable natural gas in tight formations in the continental United States vary from 192 to 574 Tcf depending upon price and the state of technology. GRI has recognized the "need for a coordinated and cost-effective research program that will advance unconventional gas exploitation technology, thereby increasing the commercialization of the resource. Previous analyses of tight gas formations have been categorized according to two simplified types of external reservoir geometry controlled by the depositional setting of the sands. "Blanket" and "lenticular" sandstone reservoirs are consistently differentiated. The GRI research program focuses on the exploitation of gas in tight, blanket-geometry sandstones. This emphasis is in contrast to the Western Gas Sands Project of the U.S. Department of Energy, that has predominantly involved analysis of lenticular reservoirs within the Piceance Creek, Uinta and Greater Green River Basins but also has included shelf systems in the Northern Great Plains Province.
A comparative survey of over 30 blanket-geometry tight gas sandstones in 16 sedimentary basins was undertaken by the Bureau of Economic Geology to assist GRI in selection of stratigraphic units, sedimentary basins, or particular depositional systems for future research and technological developments Collection of a uniform set of information for each stratigraphic unit was attempted to facilitate comparison between units (Table 1). Information submitted to state oil and gas commissions with applications for tight formation designations under the Natural Gas Policy Act served as important source material and included porosity, permeability, net pay and additional engineering data not otherwise permeability, net pay and additional engineering data not otherwise publicly available. publicly available. A critical aspect of the GRI research plan is to ensure that results of research and development in one tight sandstone trend are readily transferable to another trend. To accomplish this technology transfer, emphasis was placed on the common aspects of the geology and engineering of sandstones potentially suitable for future research. Many characteristics of sedimentary rocks are a direct product of their depositional environment. It therefore seemed likely that blanket-geometry tight gas sandstones of different ages and from different sedimentary basins could be divided into groups based on geologic similarities inherited from common environments of deposition. Such an approach, while allowing for diversity, provides a basis for anticipating the overall similarity of reservoir geology from one area to another. Review of each stratigraphic unit included emphasis on the depositional system responsible for emplacement of the unit and on the occurrence of analogous systems in other sedimentary basins.
It is evident that a very close relationship exists between reservoir geology and reservoir engineering.