Williams Production Company performed a study to improve hydraulic fracturing and field development in the Williams Fork Formation, Piceance Basin, Colorado.The Williams Fork Formation is part of the Mesaverde Group and consists of massively stacked low permeability sandstones.Wells in the Williams Fork are usually stimulated in multiple fracture stages using limited entry techniques.This paper describes how hydraulic fracture mapping was performed with microseismic imaging on two wells in the Grand Valley Field and two wells in the Rulison Field.This was part of a pilot project to assess well downspacing and to assist with stimulation optimization.Fracture length was longer than expected but varied somewhat by field, well and treatment type.Payzone coverage was good considering significant differences exist in breakdown and pore pressures of the various sands within the hydraulic fracture stage.Fracture initiation and early growth did not fully correlate with pore pressure and ISIP data from diagnostic injections but overall payzone coverage generally matched this data. Introduction This paper shows the microseismic mapping results for a four-well project performed in the winter of 2001–02.The mapping was conducted to better understand well placement and fracture optimization for a large pilot project evaluating ten-acre well spacing.Microseismic mapping was performed in the Rulison Field and Grand Valley Field shown in Figure 1.The goals of the mapping were to determine fracture orientation and dimensions (height and half-length) and treatment distribution in these fields. Overview of the Williams Fork Formation The Williams Fork Formation1–6 is part of the Mesaverde Group and consists of many stacked low permeability sandstones and formation gross thickness can exceed 2000 ft.A generalized Mesaverde section is shown in Figure 2.These are low permeability sandstones with porosities ranging from 6–14% and matrix permeability ranging from 0.1–5.0 microdarcies.All intervals are naturally fractured to some extent and effective permeability is 10–50 microdarcies.Natural fractures terminate at lithologic boundaries and do not connect layers vertically.Layers are limited in lateral extent and there is little or no correlation of intervals even with reduced well spacing.

The success of the Barnett Shale has many operators in search of similar producing formations. One such formation is the Woodford Shale which stretches from Kansas to west Texas. The Woodford is an ultra-low permeability reservoir that must be effectively fracture stimulated in order to obtain commerical production. Once a formation that was drilled through on the way to deeper horizons, this shale play now dominates drilling activity in southeast Oklahoma. Like the Barnett, initial testing of the Woodford Shale was from existing vertical wells that penetrated deeper horizons. Currently, the main exploitation of the Woodford Shale is from long horizontal wells with some lateral lengths exceeding 4000 ft. The wells are stimulated in stages with large hydraulic fracture treatments. Successful shale plays have demonstrated that production is directly related to the size of the stimulated reservoir volume. Techniques to optimize hydraulic fracturing effectiveness have been evolving in the area the last few years. Over 100 frac stages have been mapped in the Woodford Shale using surface tiltmeters, offset-well microseismic and treatment-well microseismic mapping techniques. This paper will examine the effect of lateral azimuth, formation dip and its influence on asymmetric fracture growth; the effect of existing faults and its interaction with the fracture stimulation. Additionally, stimulation size, number of stages, perforation clusters and fracture initiation problems will be discussed. Finally, a comparison to Barnett Shale type fracture networks will be made. Understanding fracture growth in the Woodford Shale willl enhance the development of the play by helping operators optimize fracture completion and well placement strategies. Overview of the Woodford Shale The Woodford Shale is of Devonian age and extends from southern Kansas, through Oklahoma and into west Texas. It is found within the black shale belt as show in Figure 1. It is easily identified by a very high gamma ray streak and is 50–300 ft thick as shown in Figure 2. Completions have been made from depths of 900 ft in northeast Oklahoma to 13,000 ft in west Texas. A typical core contains: 35–50% quartz, 0–20% calcite/dolomite, 0–20% pyrite, and 10–50% total clay. Porosity ranges from 3–9% and permeability ranges from 0.000001 md to 0.001 md. Water saturation varies from 30% to 45%. The formation is slight underpressured with pressure gradients in the 0.35 to 0.44 psi/ft range. The Woodford Shale was first produce in 1939 in southeast Oklahoma. Drilling activity that targeted the Woodford Shale as the primary objective was slow to grow. By late 2004 there were only 22 Woodford shale completions. By the end of 2006 there were 143 Woodford Shale completions.[1,2] Through mid year 2007, there had been an additional 176 wells drilled with an estimated total of 350 wells for the year (see Figure 3).

A method is decribed where microseismic mapping of hydraulic fractures is improved by using crosswell data to calibrate and/or verify dipole-sonic velocity data. The microseismic technique uses an array of advanced tri-axial receivers to detect microearthquakes induced by a fracture and, thus, provides a real-time image of the fracture and the way it propagates. To apply this technique, the orientation of the receivers must be determined by detecting perforations or other energetic sources in the treatment well, and the velocity structure of the intervening rock interval must be adequately known. Currently, dipole-sonic logs provide high-resolution velocity data, but significant errors may occur if the logs are old (e.g., formation has depleted), anisotropy is large (e.g., vertical velocity different from horizontal velocity), or several other conditions exist. In addition, faults or lithology changes may separate the wells and alter the velocity structure. Accurate location of the microseisms, and thus the fracture image, is strongly dependent on accurate information about the velocity structure. In the perforation-timing procedure, crosswell-velocity data are obtained by monitoring the firing pulse from the receiver-orientation perforations (or string shots) and recording the timing pulse along with the arrival data. From these results, a simple one-dimensional model of velocities can be extracted and used to validate, refine, or correct the detailed dipole-sonic data or provide a warning of discrepancies. The ultimate goal is improved accuracy in microseismic mapping, but the results are also useful for assessing the applicability of dipole-sonic logs. Perforation-timing measurements for velocity structure have now been performed in 10 separate projects that have been used to analyze approximately 120 fracture treatments. Introduction Because of the complexity of most petroleum reservoirs and our general lack of knowledge of important geomechanical properties, the behavior of hydraulic fractures in general oil and gas operations is poorly predicted, monitored, and evaluated. Most pre-treatment information is derived indirectly from logs, such as the case of calculating stresses and moduli from dipole sonic logs. Most monitoring and evaluation information is based on pressure behavior of the injection history or the well performance, resulting in the non-unique estimation of 3D behavior and multiple processes from a single scalar - the pressure. The Bossier formation of east Texas is a prime example of a reservoir where geologic complexity can lead to stimulation difficulties and unexpected results. The sandstone reservoirs consist of upper-slope turbidite deposits that have relatively small dimensions, bounded by both fault and stratigraphic discontinuities. As a result of these complexities, it is difficult to predict fracture behavior from first principles and perform post-fracture evaluations from only treatment pressure and production analysis. Given the importance of hydraulic fracturing to hydrocarbon recovery in this reservoir and most others, it clearly is important to develop methods to monitor or measure fractures in the subsurface. At present, there are two technologies - tiltmeter1–6 and microseismic7–33 mapping - that have some capability for fracture monitoring, although it is expected that eventually others will be developed. Of the two, microseismic monitoring has the potential to uncover detailed structural facets of the fracturing process, but only if the microseisms can be located with sufficient accuracy to discriminate between relatively closely spaced natural fractures or leakoff paths. For example, Figure 1 shows a synthetic fracture map with orthogonal structures (presumably natural fractures accepting fluid) delineated by microseisms and the same map with a random, normally distributed, 0–20 ft error imposed on each dimension of each location point. It does not require much error to fully disguise the original structure so that it appears as a simple, single-fracture map.

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