Abstract

A case study has been conducted on Red Fork formation wells with bottomhole temperatures ranging from 225-250 F. The fracturing applications and techniques in this area had historically provided lower than expected post-treatment productivity and a rapid decline rate, suggesting that the fracture conductivity were less than optimum. Joint efforts of the operator and service company, utilizing state-of-the-art fluids, breakers, and design methodologies, were employed to optimize well productivity. The case histories of hydraulic fracturing treatments and subsequent production performance of five offset wells are analyzed and presented. Average incremental production rates were significantly improved through application of the new technologies, clearly demonstrating the effectiveness of the modifications.

Introduction

The study was conducted on Red Fork formation wells in the Strong City Field. The field is located in Roger Mills County, Oklahoma, approximately 20 miles north of Elk City. The wells, which are located in two adjacent sections, were drilled either as replacement wells or as increased density wells. The Red Fork formation has been described as a Pennsylvanian Age sequence of sands and shales with a gross thickness of 700-800 ft.

A representative type log for the Red Fork is shown in Figure 1. The interval depths were 12,500 ft to 13,200 ft in the study area. The sandstone formation contains small amounts of clay minerals such as chlorite, illite, kaolinite, and mixed layer. The study wells had permeabilities ranging from 0.01 to 0.19 millidarcies and porosities from 8 to 10%. Reservoir pressures ranged from 4,670 to 9,478 psi. The wide range of pressures was due to the effects of offset drainage on these increased density wells. The bottomhole static temperature of the production zones ranged from 225 to 250 F.

Hydraulic fracturing operations have been applied in the area as a means to stimulate the wells for many years with varying degrees of success. Fracturing fluid load recovery from these treatments was typically less than 25%. Foams generated with carbon dioxide were used in an effort to address the low fluid recoveries which were believed to be associated with water retention in the reservoir. Even with the energized, low pH fluids the recovery was still typically under 25%, suggesting that fracture conductivity was less than optimum. Premature screenouts were common when aggressive proppant schedules were attempted. Additional expenses were commonly incurred as a result of proppant flowback associated with extended shut-in times after stimulation.

P. 27

This content is only available via PDF.
You can access this article if you purchase or spend a download.