Measurement in Fracture Using a Fiber
Publication Date: 2014-Jan-08
The IP.com Prior Art Database
 This disclosure relates to hydraulic fracture monitoring and other oilfield applications. More particularly, this disclosure relates to systems and methods for using a fiber held by a tool, seat packer, or by a frac ball within a wellbore. The drag force on the fiber is measured for evaluation, monitoring, and/or control of a hydraulic fracturing operation of subterranean rock formations surrounding wellbores, as well as for other applications, where a fracture ball based device or tool can be deployed into a wellbore while during a fracture job or production.
 Many hydrocarbon reservoirs worldwide have passed peak production. As about 70% of the hydrocarbon present in a reservoir is not recovered by the initial recovery strategies, many challenges and opportunities exist for so-called brownfields concerning the tail production of the field. In formations with low permeability, producing hydrocarbon is difficult. Thus, stimulating techniques are used to increase the net permeability of a reservoir. One of the techniques consists of using fluid pressure to fracture the formation or extend existing cracks and existing channels from the wellbore to the reservoir thus creating alternative flow paths for the oil or, more commonly, gas to be produced at a higher rate into the wellbore. The geometry of the new flow path determines the efficiency of the process in increasing the productivity of the well.
 There is a need for characterization of the new flow path geometry. To date, direct measurement is not possible, and the geometry is generally inferred from fracturing models, or interpretation of pressure measurements. Alternatively, micro-seismic events generated in the vicinity of the new fractures are recorded downhole. Interpretation indicates direction, length, and height of the fractures. Still, these “hydraulic fracturing monitoring” (HFM) techniques are an indirect measurement for which interpretation is hard to verify. In addition, it requires the mobilization of costly wireline wellbore seismic assets that are not a very good fit for the economics of the hydraulic fracturing market on land; and a nearby offset well is normally required for monitoring.
 Direct measurements inside the wellbore during the fracture operation are difficult and are not carried out regularly, due to complexity of such measurements and logistic involved. Also, presently, most fractures are done in horizontal wells on multiple zones isolating the zones before fracturing. This makes it even more difficult to make measurements by conventional means like wireline.
 Figures 1 and 2 below illustrate two of the most common 2D models used in fracture treatment design. The Perkins-Kern-Nordgren (PKN) geometry (Fig. 1) is normally used when the fracture length is much greater than the fracture height. See Gidley, J.L., Holditch, S.A., Nierode, D.E. et al. 1989. Two-Dimensional Fracture-Propag...