New Fracturing Technique Leads to Improved Performance in the Mississippian Trend
- R.R. Hannah (The Western Co. of North America)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- August 1976
- Document Type
- Journal Paper
- 859 - 864
- 1976. Society of Petroleum Engineers
- 2.5.2 Fracturing Materials (Fluids, Proppant), 1.10 Drilling Equipment, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.2.2 Perforating, 2.4.3 Sand/Solids Control, 3 Production and Well Operations, 1.6 Drilling Operations, 5.6.5 Tracers, 4.1.5 Processing Equipment, 4.1.2 Separation and Treating
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An unusual fracturing technique features the placement of an extremely viscous sand/water slurry, into a thick, heavily fractured carbonate. Pumping is ceased for maximum viscous recovery before injection is begun Pumping is ceased for maximum viscous recovery before injection is begun again. This fluid follows the Bingham-plastic flow model and the yield point of the fluid is used to divert treating fluid to other zones. point of the fluid is used to divert treating fluid to other zones. Introduction
This paper presents a brief history of stimulation techniques used in the massive, heavily fractured Mississippian pay in north central Oklahoma. Since these techniques generally are unorthodox, the reasons for well response are discussed.
Most of the paper deals with problems associated with gaining vertical selectivity and specifically with development in early 1974 of a technique that significantly improves such selectivity.
In this area, limited-entry techniques have been the normal means for gaining selectivity; however, because of the interconnected fracture network, it has long been suspected that only a modest portion of the pay has been affected by stimulation.
The technique presented involves the use of an extremely viscous, non-Newtonian water gel that exhibits a yield point and follows the Bingham plastic model. This fluid usually contains sand. In theory, any Bingham-model fluid could be used; however, the fluid developed for this application is characterized by an extremely high yield point and a moderate plastic viscosity.
Stages of this fluid are pumped intermittently during the treatment and pumping is stopped when the stage is displaced into the formation. Sufficient time is allowed for at least partial fracture healing to occur. When injection is resumed, the formation is overpressured by the amount required to overcome the yield point of the Bingham plastic. This overpressure is then available to open additional existing fractures, either vertically or laterally. In the ideal application, the Bingham plug will not move, so that permanent diversion is achieved. Since the regional stresses in the area appear to be low, the magnitude of pressures required for diversion is probably low. probably low. Mississippian Trend
Drilling and development in the Mississippian Trend has continued with varying degrees of intensity since the early 1960's. This area in north central Oklahoma includes Garfield, Major, Alfalfa, Kingfisher, and Blaine counties. Activity that began in the late 1950's increased to a maximum in the mid-1960's. Activity then declined but continued into the 1970's, with a strong revival evident in 1974 and 1975.
The Mississippian rocks that yield production in this area consist of two members, the Meramec and the Osage. Both these members are composed of fractured limestone, with chert present in both zones. Acid solubilities in those zones can range from 15 to 80 percent with an average of 45-percent. The Meramec varies in thickness from a few feet to 150 ft or more: the Osage commonly reaches a thickness of 400 to 600 ft. Heavy fracturing can occur in any part of this massive section; it is generally agreed that significant production occurs only from the fractured sections, with little or no production occurring from primary matrix porosity. production occurring from primary matrix porosity. JPT
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