Engineering Improvements for Red Fork Fracturing
- Frederick L. Cornell (Louisiana Land & Exploration Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- February 1991
- Document Type
- Journal Paper
- 132 - 137
- 1991. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 5.6.5 Tracers, 4.1.5 Processing Equipment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.2.3 Rock properties, 1.6.9 Coring, Fishing, 2.5.1 Fracture design and containment, 3 Production and Well Operations, 2.4.3 Sand/Solids Control, 1.14 Casing and Cementing, 5.3.4 Integration of geomechanics in models, 5.5.8 History Matching, 2.5.2 Fracturing Materials (Fluids, Proppant), 2.2.2 Perforating
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Fracturing treatments of the Red Fork formation have evolved with experience gained during the last decade. Advances in technology have resulted in improved production performance. Today, successful operators are applying more efficient designs to place larger amounts of proppant with smaller fluid volumes. This paper presents a history of Red Fork completions and describes how to develop the optimal stimulation for each Red Fork well of the western Anadarko basin of Oklahoma.
Located in the Anadarko basin of western Oklahoma, the Red Fork formation is a Middle Pennsylvanian Age (Des Moinesian) sequence of sandstones and shales. Overall thicknesses of ˜1 ,500 ft contain several different producing formations, encumbering completion optimization. The four main producing zones of the Red Fork interval are the Cherokee and the Upper, Middle, and Lower Red Fork. Various combinations of these zones are produced throughout the trend.
Multiple operators have used various fracturing fluids and techniques to maximize production. Early treatments used crosslinked hydroxypropyl guar (HPG) with 2% KCl containing low concentrations of sintered bauxite.1,2 When some wells did not perform as expected, operators emphasized fracturing fluids and techniques. Good wells, those that will produce 1 Bcf or more, have resulted from the use of virtually every type of fluid and technique. Today, after nearly 10 years, we are approaching the optimum treatment for each individual completion in the Red Fork.
A detailed data base of 165 wells containing reservoir and treatment characteristics was compiled from more than 200 wells completed in the Red Fork formation in Roger Mills and Custer counties of western Oklahoma. Of the 21 operators represented in this data base, 11 operate 90% of the wells. Five different fluids and four types of proppant were used on 99% of the wells. Completions included seven different combinations of the Cherokee and Upper, Middle, and Lower Red Fork zones. Completions in the Upper and Middle Red Fork zones or a combination thereof made up 95% of the wells studied (Table 1). Actual and projected estimated ultimate recoveries (EUR's) were used to define the best treatments and to evolve optimum fracture stimulation procedures.
Geology and Reservoir Characteristics
The Red Fork formation is composed of very-fine- to fine-grained sand deposited in a deltaic complex. Deposits are found at the transition between continental and marine environments and continue into the deeper marine basin. The area studied in Custer and Roger Mills counties represents deposits in the continental/marine transition (deltas) and the slope/basin transition (submarine fans). Five areas representing the various geologic environments within the deltaic complex were analyzed separately and as a whole to differentiate between changing reservoir characteristics (Fig. 1). The Weatherford and Clinton fields represent alluvial plain deposits; the South Butler and West Butler fields represent the delta-fringe sediments; and the Strong City field is dominated by submarine fans. Sand is most likely found in or along distributary channels because of gentle slopes and is scarce in the delta-fringe area of West Butler.
Core analyses from several wells have shown that quartz and rock fragments are the most abundant framework constituents. Primary porosity is intergranular and limited to less than 5 % of the rock volume. Quartz overgrowths are the major cement. With mechanical compaction of the granular framework, quartz overgrowths cause the major loss in PV. Secondary porosity from authigenic clay and altered framework grains is the dominant porosity type, resulting in microporosity that is marginally effective owing to the limited degree of interconnection. Microporosity has porethroat sizes of 1 µm or less. Well performance is relative to the amount of microporosity present. Log porosities exceeding 10% represent larger amounts of primary porosity and thus less microporosity. Permeability increases in wells with porosity greater than 10 % because the interconnections of pore space increase. Permeability for the Red Fork ranges from less than 1 µd to 0.5 md, depending on the amounts of primary and secondary porosity present.
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