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Treadgold, Galen (Global Geophysical Services) | Eisenstadt, Gloria (Global Geophysical Services) | Maher, John (Global Geophysical Services) | Fuller, Joe (Global Geophysical Services) | Campbell, Bruce (Global Geophysical Services)
Rock property analysis of the A large multi-client, full-azimuth 3D seismic survey of Niobrara involved processing the 3D to address both layer almost 800 square miles in southeastern Wyoming is the and azimuthal anisotropy, creating gathers with reliable far basis for a regional structural interpretation and azimuthal offset amplitudes for an elastic inversion. Initial analysis of velocity analysis of the Niobrara in the area of the Silo the layer anisotropy was performed on isotropicly migrated Field, in the northern end of the Denver-Jules Basin. The gathers using a simultaneous picking tool for velocity and unconventional Niobrara oil and gas play has been VTI (vertical transverse isotropy). VTI information was compared to the Bakken in North Dakota but variable well then used to update traveltimes and begin scanning for HTI results have long plagued operators. Silo Field has (horizontal transverse isotropy). The approach used to produced about 10 million barrels of oil since 1981 but well define the HTI involved migrating the gathers rates can vary drastically over a short distance. The study approximately 100 times to test the impact of small integrates seismically derived rock attributes, well and changes in azimuthal anisotropy (as expressed by elliptical production data, and integrated regional structural migration operators). The migration scanning result was interpretation to understand the Niobrara fracturing and to used to once again update 1-D travel times feeding a reduce drilling risk.
Copyright 2013, Unconventional Resources Technology Conference (URTeC) This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 12-14 August 2013. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitt ed by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk.
The gas producing section of the Niobrara formation is a low pressure, low permeability chalk. To evaluate the potential of this tight gas reserve, reservoir data were obtained in a systematic program. These data demonstrate that many Niobrara wells can be produced profitably when stimulated by hydraulic fracturing and that an economically optimal fracture treatment can be designed. The described techniques generally may be applied for development of a variety of tight reservoirs through hydraulic fracturing.
Gas bearing chalk of the upper Cretaceous Niobrara formation is encountered at depths of 1,000 to 3,000 ft (300 to 900 m) in parts of Colorado, Kansas, and Nebraska. The general area of the Niobrara gas producing potential is shown in Fig. 1. This low pressure, low permeability reserve has been recognized for many years. However, commercial development has become feasible only recently as a result of higher gas prices and improved stimulation techniques.
Cities Service Co.'s Niobrara development program began in Washington County, CO, early in 1979. This program was designed to evaluate the economic potential of this tight gas reserve and to determine an optimal exploitation scheme. On the basis of data obtained in a systematic well testing program, it was demonstrated that many Niobrara gas wells can be produced profitably with proper stimulation. Furthermore, the well testing data enabled the determination of an optimal stimulation treatment for a given well.
This paper describes our Niobrara development efforts focusing on the Washington County activities. The geology, reservoir characteristics, and historical aspects of the Niobrara gas play are reviewed briefly. The specific procedures used in drilling, completion, stimulation, and testing are detailed and representative well data are presented. The techniques described here generally may be applied for the judicious development of a variety of tight gas reservoirs.
Gas accumulations in the Niobrara formation generally are related to low relief structural features found along the eastern margins of the Denver basin. These structures are domal to oval and do not exhibit a strong regional lineation. Regional dips normally are less than 1 deg. and closures range from 50 to 200 ft (15 to 60 m). The structural features are modified frequently by normal faults, many of which are considered listric. These are believed to be early diagenetic features.
The most recent Niobrara wildcats have been drilled on structural features defined by existing wells where deeper beds were the objective. We have relied to a large extent on data from wells drilled to the Cretaceous D and J sands and shale sequence for locating new prospects.
The upper Cretaceous Niobrara formation was deposited over much of the central and western U.S. in a major transgressive stage of marine deposition. Two members of the Niobrara are recognized in the Denver basin area: the lower Fort Hays limestone and the upper Smoky Hill chalk. Gas production appears to come exclusively from a relatively clean chalk zone at the top of the Smoky Hill chalk member.
Owens, Matt (Extraction Oil & Gas) | Silva, Jesse (Extraction Oil & Gas) | Volkmar, Matt (Extraction Oil & Gas) | Poppel, Ben (Liberty Oilfield Services) | Siegel, Joel (Liberty Oilfield Services) | Losacano, Tony (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services)
Abstract The Denver-Julesburg Basin has been going through a new cycle of development with horizontal drilling and high-intensity hydraulic fracturing. Since the first horizontal wells in 2008, more than 4,000 horizontals have been drilled, leading to a four-fold production increase between 2008 and 2012. While completion practices have been fairly similar across the basin over these early-development years, several operators are now starting to experiment with different completion designs. The objective of this paper is to discuss the benefits of these new designs and further evaluate what completion changes deliver the most "bang for the buck" in a challenging pricing environment. Use of a novel completion design and development of a low-cost ultra-low concentration fluid system resulted in significant cost saving while maintaining or improving overall production, thus lowering $/BOE in a challenging industry environment. Lowering cost per BOE drove a process of completion design changes that started with fluid compatibility testing, including regained permeability testing in proppant load cells, which showed that a light and more cost-effective Borate Guar can result in similar or better cleanup than a CMHPG-Zirconate system traditionally used in the DJ basin. Multi-variate analysis results from an extensive petrophysical / completion / production database showed production in the basin predominantly benefits from increase proppant volume and higher stage intensity. Field implementation of this system and a design with more proppant and stage intensity focused on consistently being able to place higher proppant loadings with less polymer. More than 150 horizontal wells were completed between mid-2014 and early 2016 in T5-6N R64-67W while implementing this strategy. When compared to about 350 other horizontal wells, mostly completed without these changes, overall results of the new completion strategy have been very encouraging: Higher injection rates and improved pump time to downtime resulted in a 20+% reduction in days required to complete a typical 8-well pad. Over a period of about 130 pumping days, more than 2,100 frac stages were completed. Supply chain efficiency improvements were implemented to keep up with proppant demand averaging 3.5 million pounds of sand every day, occasionally peaking to above 8 million pounds of sand per day; A new ultra-low concentration Guar Borate system was developed that could be crosslinked at concentrations down to 8 lbs/Mgal. Together with high rate, this fluid system enables placing proppant concentrations up to 6 PPA, making the system significantly cheaper and cleaner than the conventional 20+ lbs/Mgal CMHPG systems that were routinely used in the DJ Basin. Overall production in both Codell and Niobrara was above results for nearby peers over a wide range of production metrics. A petrophysical workflow was developed to arrive at a proper apples-to-apples comparison of historical production response in the area as compared with the results associated with this new strategy. Through various statistical analysis tools such as multi-variate analysis, the authors evaluated the importance of both reservoir and completion changes, and identified several key characteristics that are closely tied to the highest production responses in the DJ Basin.