We investigated the accuracy of surface seismic attributes in predicting fracture density variations within the Nordegg Formation in west central Alberta. We know from core, drill samples, well-log, and drilling data that the Nordegg zone is fractured to some degree. These fractures are of interest because the reservoir has very low permeability, and therefore natural fractures may materially affect well performance. 3D surface seismic techniques such as amplitude variation with azimuth or azimuthal AVO (AVAz), variation of velocity with azimuth (VVAz), curvature, and coherence techniques are all tools that have been used to predict fractures in a qualitative fashion. In this study, we wanted to understand how well these attributes predicted the reservoir quality in a quantitative fashion. Previous quantitative studies have used image log orientation data or estimated ultimate recoveries (EUR) in vertical wells as validation data. The conclusiveness of these studies has been subject to several problems: firstly, the limited sample statistics provided by vertical wells applied to the validation of lateral variations, and secondly by the potential nonuniqueness of the EUR to fracture density relationship.

A common trend in our industry is to minimize gel concentrations and utilize the lowest viscosity fluid available to place proppant Barrett Resources Corporation has found, for lenticular microdarcy formations, that one of the keys for success is enhanced proppant transport. This is achieved incorporating stable gels which maintain greater than 1000 cpa viscosity at bottomhole static temperature for the duration of the treatment. An extensive case study has been completed, involving over 500 fracture stimulation treatments in more than 175 wells, that illustrates the poor results achieved in the Williams Formation of the Mesaverde Group using low viscosity fluids. Low viscosity fluids invariably exhibit poor proppent transport. The statistical study shows that larger treatments utilizing "perfect proppant transport" fluids gain superior results. Based upon the case study, 100% economic success has been achieved upon incorporating stable fluids containing delayed breakers, reducing ped volumes to less than 5% of total job size, and minimizing echelon fractures while implementing a limited entry stimulation technique. Background Barrett Resources Corporation has drilled and completed over 175 Williams Fork producers across the Grand Valley, Parachute and Rulison Fields within the Piceance Basin of Western Colorado (Figure 1). The Williams Fork Formation lies within the upper portion of the Cretaceous Mesaverde Group and is the primary target for development in the area. Depths range from 5900 to 8300 feet. Each well must be fracture stimulated to yield commercial production through a series of limited entry treatments ranging from one treatment to as many as six fracture stimulations to complete the entire gas saturated section. An interval from 100 to 600 feet in gross thickness may be considered for an individual treatment. Limited entry techniques must be employed to stimulate the numerous and discontinuous lenticular bodies or point bars within a selected interval. Evaluating the success of previous stimulations to optimize future treatments caused Barrett to embark upon a large statistical study of our completion practices. Prior to the study, Barrett essentially perforated most mud log shows in attempting to recover gas from the numerous lenticular sands present in each well. A typical perforating scheme would include 20 to 30 holes distributed between 5 to 10 sand bodies within a zonal treatment. Stimulations ranged from 100,000 lbs. of sand to 350,000 lbs., incorporating through time, virtually every water based fluid available. As a result, a statistical analysis of the previous treatments produced a number of meaningful conclusions enabling Barrett to improve gas recovery while reducing overall well cost. Geology The gas saturated portion of the Williams Fork Formation is 1700 to 2400 feat in thickness and encompasses all of the peludal interval (commonly referred to as the Cameo), the coastal, and the majority of the fIuvial interval (Figure 2). The formation consists of interbedded silts, shales, and sands with numerous coals interspersed throughout the paludal (lower) section. All of the sands are fluvial in nature and are very heterogeneous and discontinuous. The two main fluvial (river) deposits are distributary channel sands and meanderbelt complex sands. P. 293

In 1991, Union Pacific Resources Company (UPRC) stimulated four horizontal wells in the Niobrara Formation in the Silo field, Laramie County, Wyoming. Stimulation treatments were required due to the rapid production declines seen early in the life of these wells, which were completed in 1990 and 1991. Horizontal and vertical wells in the Austin Chalk formation have been stimulated by injecting large volumes of water (10,000–30,000 bbls) at high rates (50-220 bbl/min) to improve productivity. This stimulation technique was applied in the Silo field because the Austin Chalk and Niobrara reservoirs have similar features; the most important similarity is that productivity requires connection to an adequate natural fracture system. These Niobrara stimulation treatments consisted of 30,000 bbls of water pumped at rates up to 150 bbl/min with wax beads as diverting material. This paper describes the job designs, bottom-hole treating pressure (BHTP) trends observed during the job, and post-treatment well production. Early BHTP responses and post-treatment production are related to the extent of natural fracturing exposed within the horizontal (lateral) sections. The lack of sustained productivity after the treatments indicates that Niobrara wells respond differently than Austin Chalk wells after large-volume, high-rate treatments. The most likely explanation for this difference is that fractures opened during Niobrara large-volume, high-rate treatments either close during production or do not provide sustainable connectivity to high-conductivity fractures. Future treatment strategies are discussed concerning fluid selection and the use of diverting materials and proppants.

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