Evolution of Fracturing the Cotton Valley Sands in Oak Hill Field
Authors: Tindell William A. , Neal Jack K. , Hunter J.C. 
Published: December 2007

Fracturing in the Oak Hill field has changed gradually as experience has been gained with data from openhole logs, prefracture pressure buildup surveys, and postfracture tracer logs. Prefracture pressure buildups are used with a computerized pressure buildups are used with a computerized reservoir simulator to predict production performance after stimulation. Fracture geometry performance after stimulation. Fracture geometry and pressure buildup analysis become increasingly important as the present infill drilling progresses.

Introduction

The Oak Hill field in northeastern Rusk County, TX, has several producing formations; however, this paper focuses only on the Cotton Valley Sand series paper focuses only on the Cotton Valley Sand series in the field (Fig. 1). The 28 wells on which data are presented (Table 1), starting with the first well presented (Table 1), starting with the first well completed in Nov. 1976, are operated by the same company. Results of another 30 wells in the field operated by others provided additional bases for improvement in fracture treatment procedures.Three broad aspects of the program are reviewed, including case histories, reservoir simulator studies, and considerations for improvement in future fracture stimulations. Several subject-related sections are presented with conclusions and/or reasons for change of procedures at the end of each section.

Early History

Completions of the first five wells included a series of two to four fracture jobs, separated with sand plugs, which extended over the entire Cotton Valley Sand series from the Bessier shale to the B limestone - a section of approximately 1,400 vertical ft. Each fracture job was performed on two to six sand members through 2 7/8-in. tubing with a minimum of two holes per sand for a total of 16 to 19 holes so that a strict limited-entry fracture treatment could be performed. The treatment was spearheaded with 2,000 gal of 10 or 15% HCl with balls on the bottom stage for perforation breakdown. No balls were used above a sand plug. Equal fluid volumes containing 1, 2, and 3 lbm/gal of 20-40 mesh sand followed the pad at injection rates of 15 to 25 bbl/min. Proppant pad at injection rates of 15 to 25 bbl/min. Proppant was tailed in with radioactive tracer material. Fifteen jobs were executed essentially as designed with only three screen-outs, all of which occurred after about 90% of the designed volume had been pumped.Although the deepest zone fractured often was allowed to flow a short time before performing the other fracture stages, the succeeding stages exposed the formation to full volumes of fracture fluid for several days--i.e., until two or three additional fracture jobs and sand washing could be performed. This procedure, in part, defeated the purpose of having a gas sales line ready for early fracture fluid flowback and continuous formation production until complete cleanup was achieved. Completion of the sixth well included plans for three fracture stages similar to those used in the first five wells. Concern about formation retention of fracture water prompted an extended cleanup period after the first fracture stage. Only the Taylor zone, the +/- 300 gross ft of the deepest Cotton Valley Sand series, was fractured. No further stimulation was performed because the Taylor zone treatment resulted performed because the Taylor zone treatment resulted in the best gas well to date with negligible water production. production. From fracture treatments of the first six wells the following conclusions and/or comments are offered.1. The Taylor zone appears to have the highest potential. Water production problems in the first potential. Water production problems in the first five wells may be coming from the middle and upper sands.2. The sand plugs have provided positive separation between the fracture jobs and have allowed multiple fracture stages without the necessity of killing the well.

JPT

P. 799