Hydraulic Fracturing the Best Producer - A Myth?

Abstract

In oilfield operation, stimulation is mostly applied on low rate hydrocarbon producers. It is generally difficult to convince management to treat the higher or best producers in a field due to risk of damaging the wells, reluctance to shut in the well (deferred revenue) and more commonly due to misconception that stimulation is a "cure or medicine" for low rate producers or when production drops suddenly. In this paper we describe the analysis of data obtained from formation testers, well logs (petrophysical and rock mechanics), well testing, material balance, core and Nodal for a high producer well that was hydraulically fractured. Production from the well doubled after the treatment with pay out time of less than thirty days. The key to success is integration of all data, transforming data into knowledge and using it to make appropriate practical decision. This is the methodology of Power COMPLETE™ (Production Optimization With Enhanced Reservoir Characterization, Stimulation and Completion) solution process where the three elements to success are effectively combined - People, Technology and Process (PTP). Transparent relationship between the service provider and operator is required to convince all related parties to implement the project. Introduction In oilfield operation, stimulation is mostly applied on low rate hydrocarbon producers. It is generally difficult to convince management to treat the higher or best producers in a field due to risk of damaging the wells, reluctance to shut in the well (deferred revenue) and more commonly due to misconception that stimulation is a "cure or medicine" for low rate producers or when production drops suddenly. Conventional stimulation treatment cannot effectively revive low rate producers if the low producttivity is related to reservoir depletion (may require combination of stimulation and artificial lift) or change in geology and petrophysical parameters (i.e. low porosity or permeability at the flank of the field). Low porosity or permeability wells will require larger fracture treatment design (long narrow frac); thus needing more equipment (hydraulic horse power) and products (fluid and proppant). Consequently the pay out time is longer or the ROI is lower. High rate producers in the same reservoir usually have higher permeability. These wells are more susceptible to damage during the drilling and completion process due to high fluid loss especially spurt losses. Higher rate relates to higher velocity in the porous media which enhances the fines migration problem. In reality, hydraulic fracturing these wells require less equipment and products, yielding higher production increase in absolute terms consequently provides excellent economic benefits (lower payout time and higher ROI). General Geology and Geophysics Description Geological and geophysical studies on Field "A" date back nearly three decades ago. Dia Din and Brogden (1973) give a good overview of the basic structure and stratigraphy. As more data became available, geoscientist began realizing the importance of wrench tectonics to the area (e.g., El-Shaarawy & Zaafan, 1994; EGPC, 1992). The complexity of such a setting and the fact that structural movements began during deposition of reservoir strata make integrated structural/stratigraphic interpretations both needed and challenging. The seismic data was acquired in 1983 and 1984. The line spacing or grid was approximately one kilometer, oriented northeast - southwest, with tie lines northwest - southeast. There were a few infill or detail lines shot over the Field "A" and over some previously mapped leads.