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The Niobrara Shale in the United States has ramped up into a hot play that could soon bring an explosion of horizontal drilling in Colorado and Wyoming. The combination of horizontal drilling and multistage hydraulic fracturing is transforming the Niobrara from a target that has been drilled vertically and primarily for gas for nearly 100 years into a liquids-rich play that is capturing considerable attention. Speaking at the 2011 SPE Annual Technical Conference and Exhibition in Denver, John Ford, general manager of Colorado’s Wattenberg field at Anadarko, described the growing Niobrara activity as “really the next big thing.”
That optimism was understandable. In November, Anadarko announced that its leases at Wattenberg may hold more than a billion barrels of recoverable oil and natural gas. The statement noted company drilling success in 11 recent wells at the field, including the Dolph 27-1HZ horizontal well that showed initial production of more than 1,100 B/D of oil and 2.4 MMcf/D of natural gas. These latest wells have given the company confidence that it can drill between 1,200 and 2,700 wells in northeast Colorado, with approximately 160 wells planned for this year. Based on results so far, the company expects ultimate recovery of between 500 million and 1.5 billion bbl of oil, natural gas liquids, and natural gas on an equivalent basis.
Anadarko is not alone. Chesapeake Energy, Noble, Encana, and EOG Resources are among the largest acreage holders and the most active drillers of many companies—including numerous small independents—probing the Niobrara. Majors such as Shell and Marathon Oil have significant acreage.
There are more than 50 operators in or near the Wattenberg field alone. Situated north/northeast of the Denver area, Wattenberg is the largest producing field in the Denver-Julesburg (D-J) Basin and one of the largest onshore oil and gas fields in the US.
Reservoir Rock and Producing Regions
Although the Niobrara is usually referred to as a shale, its reservoir rock consists primarily of limestone or chalk intervals, said Steve Sonnenberg, professor of petroleum geology at Colorado School of Mines in a recent edition of the AAPG Explorer (published by the American Association of Petroleum Geologists). “The formation demonstrates facies changes that range from limestone and chalk in the eastern end to calcareous shale in the middle and eventually transitioning to sandstone farther west,” said Sonnenberg, a past president of AAPG. “Depth and thickness are highly variable.”
Abstract Consistently and continuously applied fracturing, reservoir and production engineering used to increase recovery from a marginal production low-permeability and low-pressure dry-gas reservoir has approximately doubled the initial production rate and the estimated ultimate recovery expected from new wells. The on-going costs of the additional engineering and technology to sustain the increased productivity of this reservoir is a few cents per MCF. As a result, new, wells can be drilled and produced economically, the selection criteria for acceptable infill and exploration locations is greatly expanded, and proven gas reserves for both the new wells and the region are increased. Significant performance improvement can be achieved using a minimum number of wells, consistently collected data, and continuous review of performance changes caused by completion procedures changes. Exploitation optimization is an evolutionary process, not a one time study. Introduction The Niobrara Chalk Reservoir located in Eastern Colorado and Western Kansas was originally discovered in 1912, but was not commercially developed until the mid-1970's when a combination of increased gas prices, tight-gas tax incentives and improved fracturing technology permitted economic completion of the low-pressure dry-gas reservoir. During the gas price peaks in the early 1980's the reservoir was extensively drilled because the probability of a non-economic well located in an offset or extension location was low, drilling, completing and operating costs were low, and profitability was reasonable. However, the enthusiasm to drill waned as gas prices fell and producing economics of wells became marginal. Typically, operators with similar, marginally-economic, reservoirs are reluctant to apply and use the currently available technology due to the additional procedures required to obtain data, the costs of obtaining and analyzing the data, additional complications with logistics to complete wells, the requirements to continue well monitoring and the possibility that well completion and operating costs will increase without enjoying a significant increase in either productivity or ultimate recovery. Consequently, optimization studies of low-productivity reservoirs are often conducted which focus on only one aspect of a drilling, completion, or production program. This type of optimization study may reduce costs connected to the particular aspect examined, but may increase costs in another. Further, such optimization studies are conducted with little attention paid to expected ultimate recovery since economic rate-of-return is most readily affected by cost reductions during the first year of production. Exploitation optimization, especially in marginal reservoirs, requires attention to both cost and recovery. Two operators with producing wells completed in the Niobrara Chalk determined their needs required a full, integrated geologic and reservoir study to maximize the value of the reserves from this reservoir. The goals of the on-going study are both to increase the proven reserve potential for several hundred in-fill and step-out locations in existing fields and to determine the best locations for exploratory wells in newly acquired acreage. The results to date include approximately doubling initial production rates and ultimate recovery from new wells, increasing productivity of certain existing wells, significantly reducing the number of marginal producing wells, and providing selection criteria for exploratory locations which has essentially eliminated dry-holes. P. 531
Li, N. (Black Hills Exploration and Production) | Mayerhofer, M. (Liberty Oilfield Services) | Childers, A. (Black Hills Exploration and Production) | Weitzel, B. (Black Hills Exploration and Production) | White, R. (Black Hills Exploration and Production) | Lolon, E. (Liberty Oilfield Services) | Melcher, H. (Liberty Oilfield Services)
Abstract The operator has drilled and completed a number of 8,000 to 10,000 foot horizontal wells in the Niobrara Formation in the Piceance Basin in Colorado. The Niobrara Formation in the Piceance Basin is a 1,200 foot thick gas-producing pay-zone of complex rock properties with (35% to 65%) clay-content, 0% to 2% porosity, and .01 to 10 μD permeability. The exploration program had three major items to address: the optimal zone in which to land the horizontal wells; the proper orientation of the horizontal wellbore in that zone; and how to complete the horizontal wells effectively. The operator believes maximum production in the Niobrara will be achieved by optimizing hydraulic fracturing operations to create the largest quality reservoir contact. The operator used an iterative methodology for evaluation, modeling, completion, and production diagnostics. Triple-combo and spectroscopy logs have been used to determine that the highest quality reservoir targets are carbonate-rich layers. Borehole images were analyzed to identify that natural fracture orientation varies as a function of depth. Dipole-sonic interpretation indicates a maximum stress direction of 33 degrees NE with approximately 350 psi difference between maximum horizontal stress σM and minimum horizontal stress σm. Multi-layer fracture modeling suggested targeting calcite-rich members (10%-20%) of the Niobrara with a well azimuth of NW-SE oblique to natural fractures and perpendicular to maximum stress direction with a slight up-dip well trajectory. Fracture geometry has been confirmed and constrained using real-time micro-seismic, downhole tilt-meters, fracture modeling and production behavior. Production logs show variable stage-by-stage production and provide data to feedback for appropriate revisions to the completion design and landing point. Analysis of pertinent data led the operator to utilize diverting agents and various pump schedules in future wells to attempt to activate more clusters within a stage. Proppant selection, proppant quantity, and job size were optimized to increase fracture conductivity and maximize reservoir contact. Production logs and verification of fracture geometry point to field communication and network conductivity; balancing landing point and wellbore spacing is key to optimize recovery.
Iriarte, Jessica (Colorado School of Mines, Unconventional Natural Gas and Oil Institute) | Katsuki, Daisuke (Colorado School of Mines, Unconventional Natural Gas and Oil Institute) | Tutuncu, Azra N. (Colorado School of Mines, Unconventional Natural Gas and Oil Institute)
Abstract Decreasing fracture effectiveness due to conductivity decay is a strong contributor to the steep production decline commonly observed in shale plays. The conductivity of a fracture is determined experimentally by measuring the pressure drop of a fluid flowing through a uniformly distributed proppant bed in a core with fixed length and height. Fracture conductivity degradation results from damage mechanisms and fluid interactions that occur during hydraulic fracturing operations. Rock softening and proppant embedment are some of these damage mechanisms. The impact of these interactions can be observed by measuring fracture conductivity in the laboratory under stress states similar to field conditions. This study is based on experiments performed on fractured and propped Niobrara core plugs. The samples were characterized using X-ray Diffraction (XRD), and X-ray Fluorescence (XRF), and helical CT-scans. The experiments were performed on a triaxial stress test assembly to monitor the chemical and mechanical alterations in the formation, proppant, and fluid under reservoir conditions. To achieve this, fluid chemical composition, dynamic and static moduli, and conductivity were obtained. The setup was used for the simultaneous acquisition of stress, ultrasonic compressional and shear wave velocities, flow data and fluid sampling. The results from this study indicate that stress-dependent, long-term fracture conductivity shows the sharpest decline in the early stages of the experiment. The associated fluid sample analysis indicates that the highest physicochemical dissolution of most of the elements is happening at the early contact of the fluid with the rock and is later enhanced by the pressure increase in the system. A comparison with the conductivity measurements performed on Vaca Muerta samples shows a similar behavior, yet a steeper initial decay than that observed in the Niobrara samples. The difference observed between the two samples is related to the mineralogy of the formation and the high proppant embedment observed in the Vaca Muerta samples. Although higher softening occurred in the Niobrara samples, larger embedment was observed in the Vaca Muerta sample. This experimental observation is an indication that the conductivity damage varies not only with the mineralogical content of the formation, but also with the distribution of minerals along the fracture face. Geomechanical, geochemical, and flow data integration provided a better understanding of proppant embedment and mineral distribution of the rock. It is the conclusion of this study that even if the intact core sample contains an average mineralogical composition, the heterogeneity caused by variations in the mineralogy at where the fracture is induced has the biggest impact on embedment.
Abstract All intervals within the Smoky Hill Mbr. of the Niobrara Formation (informally, Nio "A", "B", and "C"), as well as the overlying Sharon Springs Mbr. of the Pierre Shale have bentonites which range from 4" thick in the Sharon Springs to <1/8" thick within the Niobrara marls. All individual bentonites fall below wireline log resolution (with the exception of resistivity imaging); consequently, we emphasize their distribution with UV photos that highlight each bentonite based on bright UV fluorescence. Rock mechanical properties such as Poisson's Ratio and Young's Modulus calculated from dipole sonic logs are largely ignorant of the presence of these abundant, thin, yet very weak, ductile bentonites. Hydraulic stimulation modeling based on wireline log properties, therefore, grossly underestimates the mechanical heterogeneity of the Niobrara. Furthermore, the bentonites are too thin and weak to be successfully plugged for static rock mechanics evaluations. To address these limitations, we made extensive usage of the Equotip™ "Bambino" micro-rebound hammer to measure closely spaced Unconfined Compressive Strength (UCS) at least every 6" while also covering each and every one of the hundreds of thin bentonites. The UCS from the micro-rebound hammer is compared with wireline dipole sonic based dynamic rock mechanics parameters. The Equotip-derived UCS curve, even when running-average-smoothed, demonstrates much greater UCS dynamic range, capturing the very weak bentonite interbeds. Not only do the bentonite (and marl) interbeds divide the chalks into multiple subtle mechanical stratigraphic intervals, but marly intervals with most abundant bentonites can be shown to impact hydraulic fracture efficiency by limiting proppant placement to the main chalk benches. While fluid-filled fractures have rather extensive vertical propagation throughout the Niobrara A-B-C at peak pump rates, fracture offsets across bentonites and ensuing proppant embedment phenomena eventually render the main marl intervals as barriers to effective stimulation. The impact of bentonites on hydraulic stimulation efficiency was supported by proppant tracer studies in a vertical well stimulation scaled to be proportionate to an individual horizontal frac stage. Bentonites changed from our "foes" to our "friends" because their impact on zone- specific completion efficiency supports our multi-well development plans with separate A, B, and C horizontal well targeting.