The primary goal of a hydraulic fracturing treatment is to create a highly conductive flow path to the wellbore that economically increases well production. In moderate and high permeability wells the lack of adequate fracture conductivity is a limiting factor in the production potential of the well, whereas in tight gas reservoirs the limiting factor is often the effective fracture half-length. Even in the last case, adequate fracture conductivity is important to allow efficient recovery of the fracturing fluid. Traditionally, efforts to enhance conductivity have been directed to improve the ability to flow through a porous proppant pack. The industry has extended significant efforts towards the goal of increasing proppant pack permeability through the development of less damaging carrier fluids, higher strength man-made proppants, more efficient fracturing fluid breakers and so on. As an industry however, we continue to struggle with the fact that well testing frequently indicates disappointingly shorter or less conductive fractures than designed. Multiple studies indicate that proppant-pack retained permeability is often a small fraction of the maximum expected value. This manuscript describes a novel hydraulic fracturing technique that enables a step-change approach towards increasing fracture conductivity. The technique is based on the creation of a network of open channels inside the fracture. Modeling and experimental work indicates that the new technique can deliver conductivities in excess of ten-times those obtained from conventional fracture treatments. Extensive lab-, yard- and field- scale experiments combined with theoretical work allowed creating the framework that describes the physical processes occurring during the application of this new technique. By providing significantly higher fracture conductivity, this new fracturing approach delivers a number of consequential benefits: better fracture cleanup; lower pressure loss within the fracture; longer effective fracture half-lengths, all of which will contribute to improved short- and long-term production. A 15-well field study, selected from over fifty treatments performed up to date with this technique, is presented to show posttreatment results with significant gains in well production and expected ultimate recovery with respect to offset wells treated with conventional fracturing methods.
TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractCleanout of proppants, cuttings and fines in well construction and production phases are typical of oilfield operations. To make these processes successful, extensive research efforts have been done on the development of (i) equipment such as concentric pipe, tubing-operated pump-to-surface bailer and coil tubing with jetting; (ii) engineering operation control and software simulation such as conventional high-rate circulation, reverse circulation, three-segment hydraulic modeling; and (iii) carrier fluids with suspension capabilities.The development of equipment is generally expensive, and often operation limited. Software simulation and control of operation parameters are normally not able to achieve the expected cleanout effectiveness due to the process complexity. Development of novel fluid systems is the only way forward to simplify the cleanout puzzle, and extensive research has been done to improve the efficiency of carrier fluids. The most commonly used fluids are brines, drilling fluids, foams and viscous polymer fluids.The paper describes the laboratory development of a novel viscoelastic surfactant-based cleanout fluid system and its successful field application. This fluid has several advantages over conventional polymer systems. Viscoelastic surfactant systems are non-damaging to the reservoir, has excellent suspension capacity, adjustable density for hydrostatic head and low friction.
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.
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