Microseismic Fracture Mapping Optimizes Development of Low-Permeability Sands
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 95637, "Microseismic Fracture Mapping Optimizes Development of Low-Permeability Sands of the Williams Fork Formation in the Piceance Basin," by S.L. Wolhart, SPE, Pinnacle Technologies; C.E. Odegard, SPE, Williams Production; and N.R. Warpinski, SPE, C.K. Waltman, SPE, and S.R. Machovoe, SPE, Pinnacle Technologies, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.
A study was made to improve hydraulic fracturing and field development in the Williams Fork formation, Piceance basin, Colorado. Wells in this formation usually are stimulated in multiple stages by use of limited-entry techniques. Microseismic imaging was used to assess well downspacing and to assist stimulation optimization.

Introduction
Microseismic mapping was performed on a four-well project during the winter of 2001–02. The mapping improved the understanding of well placement and fracture optimization for a large pilot project evaluating 10-acre well spacing in the field. The goals of the mapping were to determine fracture orientation and dimensions (height and half-length) as well as the treatment distribution in these fields.

Background
As shown in Fig. 1, the Williams Fork formation is part of the Mesaverde group and consists of many stacked low-permeability sandstones. Gross formation thickness can exceed 2,000 ft. These low-permeability sandstones have porosities ranging from 6 to 14% and matrix permeability ranging from 0.1 to 5.0 µd. All intervals are naturally fractured to some extent, and effective permeability is 10 to 50 µd. 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 between wells even with reduced well spacing.
Gas in place averages 40 to 100 Bcf per 640-acre section. Estimated ultimate recovery is 1.3 to 1.7 Bcf/well in core areas. The recovery factor for wells on 20-acre spacing is approximately 40%, and for 40-acre spacing it is approximately 20%. At the time of this testing, the fields were developed primarily on 20- to 40- acre well spacing.

Stimulation Practices
Hydraulic fracturing is required to sustain commercial production from these low-permeability reservoirs. Fracture treatments usually are in multiple stages with limited-entry procedures. Each fracture stage targets three to six sands. Early treatments used crosslinked-gel fluid. Beginning in 2001, some wells were stimulated with waterfracs. Typical waterfrac designs consisted of 80,000 to 140,000 gal of slickwater plus 90,000 to 160,000 lbm of 20/40-mesh Ottawa sand pumped at 40 to 50 bbl/min. Typical gel fracture-treatment designs consisted of 60,000 to 140,000 gal of 30-lbm/1,000-gal crosslinked gel plus 300,000 to 700,000 lbm of Ottawa sand pumped at 40 bbl/min. Stages covered gross intervals of 300 to 500 ft with four to six sets of perforations. Both the waterfracs and gel fracture treatments were limited-entry designs with 18 to 20 total perforations. Average sand concentration was 1.2 lbm/gal for the waterfracs and 5.0 lbm/gal for the gel fracture treatments.