A Case History: Fracturing the Morrow in Southern Blaine and Western Canadian Counties in Oklahoma

Abstract

Summary Recent hydraulic fracturing treatments in southern Blaine and western Canadian Counties of Oklahoma show that the Morrow formation in this area can be fractured successfully and profitably. Hydraulic stimulation often has been avoided in the past because of water-sensitive clays commonly found in the Morrow. Included are a history of Morrow treatments in the area, and a summary of recent treatment techniques and their results. Also, an economic analysis of these results is included using 2 years' actual postfracture production history. Introduction The petroleum industry has spent a great deal of money on developing the deep Morrow gas sands of western Oklahoma in recent years. To maximize the producing rates and ultimate recoveries of these wells, it is important to evaluate the feasibility of hydraulic stimulations. This study evaluated the Sun wells located in the southern half of Blaine County and the western third of Canadian County (Fig. 1). The Morrow sand over much of this area has proved a prolific producer of natural gas. Because of the high initial bottomhole pressures (BHP's), these wells are often good commercial producers without stimulation. Hence, to avoid the possibility of reservoir damage from swelling formation clays (Table 1) fracturing generally has been avoided. As a result of this reluctance to treat and of the low permeability typically found in the Morrow, many wells have been abandoned with relatively high BHP's and significant reserves. Sun Gas recently has done considerable testing of the use of hydraulic fracturing in this area. The result has been a multifold increase in deliverability with increased economically producible reserves. It is not the intent of this paper to explore the theory applicable to these treatments, but to present the results of actual field tests and economic evaluations of these results. History of Morrow Stimulations Three factors ar-e significant for earlier treatments of the Morrow formation. The first is that only a small percentage of the wells were stimulated (Fig. 2). The second is that little or no proppant was used in these fracture treatments. An average treatment might use 10,000 Ibm (4500 kg) compared with 30,000 to 75,000 Ibm (14 000 to 34 000 kg) used in recent jobs. The third is that, with a few exceptions, the older wells treated were very poor before treatment. It was generally considered too risky to stimulate a well that was a commercial producer without stimulation. It is important to note that, despite these factors, the majority of the stimulations were successful. Research on Sun-operated wells in this area did not turn up a single instance where production was reduced as the result of a fracture treatment. Typically. the treatments before 1965 were gelled saltwater fracture treatments. These were fairly small in volume, averaging about 20,000 gal (76 m3) compared with 40,000 to 60,000 gal (150 to 230 ID 3 ) used in recent treatments. As mentioned previously, they normally contained 10,000 Ibm (4500 kg) of sand or sand and walnut hulls. Later, the trend was to use 20,000 to 40,000 gal (76 to 150 m 3) of gelled 3 % HCl with similar sand concentrations. The treatments and results of Sunoperated wells are summarized in Table 2. Test Results The test program consisted of seven fracture treatments with each well showing a significant improvement in deliverability as a result of fracturing. JPT P. 507^