Abstract

The Red Fork, a member of the Pennsylvanian age Cherokee group in western Oklahoma and the Texas panhandle, has been the target for major drilling and completion activity for several years. During 1979-81, several wells were completed in the Red Fork with varied results. The history of these completions and treatments has been traced and determinations have been made as to why post-1981 completions have shown better results than pre-1981 completions. From these results and with the aid of computer monitored pump-in/flow-back tests, the Red Fork may be "typed" by an empirically derived correlation. Thus completions can be designed for this particular "typed well" response. With the information obtained from the pump-in/flow-back test (i.e., maximum proppant concentration, maximum pumping time, and fracture closure pressure), a stimulation treatment may be designed for maximum proppant placement. After placement of the proppant, a technique may be applied to induce closure so proppant is trapped in the producing interval instead of depositing in the bottom of the induced fracture, which may not be a portion of the producing interval. An example would be a large shale section or a section having such low permeability or porosity that is below the perforated section such that production may be below the economic payout of the well. This paper presents (1) field treatment histories, (2) analysis of completion success pre- and post-1981, and (3) methods of job design to help achieve maximum proppant placement in the Red Fork Formation.

Introduction

The Red Fork Formation is a Pennsylvanian age reservoir of the Anadarko Basin in western Oklahoma and the Texas Panhandle. The Red Fork is a sandstone formation containing clay minerals such as illite, kaolinite, and mixed layer; it also contains iron rich minerals like chlorite and sometimes siderite. Acid solubility varies from 4 to 15% and Young's modulus ranges from 4.9 to 8.5E6 psi. Formation thickness varies from 40 to over 100 ft, while permeability measures less than 0.1 millidarcy and porosities range from 8 to 12%. Red Fork wells have been stimulated using nearly all types of treatment fluids and techniques in an effort to find an optimum type or kind of treatment. Early treatments were performed using a crosslinked hydroxypropyl guar (HPG) at 40 to 60 lb/Mgal, placing 3 to 4 lb/gal maximum proppant. Later treatments were performed using a 60 lb/Mgal HPG fluid with no crosslinker; sometimes with no fluid loss additive, sometimes adding 5% methanol, and with maximum proppant concentrations of 4 to 6 lb/gal. With the development of carbon dioxide (CO2) foam technology, foam fracturing treatments consisting of 70 Quality CO2 (70% CO2, 30% liquid phase) were performed, Usually mixed with 2% KCl water containing HPG gelling agent at a concentration of 40 lb/Mgal. Proppant concentrations were in the 2 to 4 lb/gal range until the introduction of the constant internal phase technique, which allows higher maximum proppant concentration. More recently, introduction of a delayed crosslinker has brought back treatments using crosslinked fluids and proppant concentrations of over 8 lb/gal. Currently, treatments employ either a delayed crosslinked 50 to 60 lb HPG, or a 65-70 Quality CO2 foam using 40-50 lb HPG as the liquid phase. In both cases maximum proppant concentration is 4 lb/gal ISP (Intermediate Strength Proppant). It is believed that the conductivity provided by this amount of proppant is adequate for production considering the difference between the formation conductivity (kih) and the fracture conductivity (kw). Data presented by Parker and McDaniel, and McDaniel, show that it may be necessary to place even higher proppant concentrations in the fracture to overcome closure effects and further improve stimulation results.

P. 299^

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