A Practical Guide to Hydraulic Fracture Diagnostic Technologies

Abstract

Abstract Hydraulic fracturing is key to the economic success of many oil and gas fields around the world and has improved production in low permeability reservoirs for more than 50 years. Successful stimulations are engineered to place the proper type and volume of slurry based on estimating the dimensions of the optimal fracture to be created in a specific wellbore. Several commonly used technologies are available which determine important fracture parameters such as fracture dimensions, fracture orientation, fracture conductivity and proppant placement effectiveness. Fracture models are today's most widely used tool to predict the optimal frac geometry based on conditional inputs such as closure stress, pore pressure, permeability, fluid saturation and numerous other mechanical and petrophysical properties of the reservoir. In many cases, these parameters are based on assumptions rather than hard data, and incorrect assumptions then lead to sub-optimal stimulation results. Direct near-wellbore diagnostics such as radioactive tracers and temperature logging are often used to gather information about fracture height and proppant placement effectiveness, while direct far-field diagnostics such as tiltmapping and microseismic fracture mapping are used to determine hydraulic fracture dimensions and orientation. Direct fracture diagnostics alone only tell the story of what happened after the fact on a given well, but they can also be used to build a calibrated fracture model which accurately predicts fracture growth in a reservoir. Depending upon the critical information needed for specific fracture stimulation, one or more diagnostic tools may be applied. These diagnostic tools will be discussed and compared in order to provide a reference of widely used diagnostic tools with strengths and limitations discussed along with examples of each in use in fracture optimization. Fracture Complexity For many years, fractures were assumed to be bi-wing, single planar features (mostly for easier numerical modeling) that would stay primarily within the pay zone and grow very long (Why would they want to grow anyplace else?). More than 10 years of direct fracture diagnostics and over 6000 mapped fractures have proven those assumptions to be mostly incorrect. Fractures in the real world are very complex. Numerous cases have been documented in the literature with direct fracture diagnostics, mine-backs and core-throughs where fractures are seen in multiple parallel planes, in multiple directions, and in "T-shaped" fashion with both horizontal and vertical components. Existing literature is rife with cases of incomplete coverage of pay zones where fractures may miss entire perforated intervals, only partially cover some intervals, grow primarily out of zone in others, deviate significantly from the wellbore causing connection or link-up problems, and grow into unwanted water or gas intervals nearby. Fracture mapping can be used in real-time to evaluate whether the entire pay is being sufficiently stimulated, whether the design calls for enough or too many stages, whether the optimal fracture length has been achieved and whether adjustments need to be made to the existing treatment design. Diagnostics Groups Fracture Diagnostics can be broken into 2 main groups (see Figure 1): Indirect and Direct Diagnostics. Indirect techniques include fracture modeling, well testing and production data analysis, while Direct measurements are further subdivided into Near-Wellbore (such as radioactive tracers, temperature, and production logs) and Far-Field (tiltmeter and microseismic mapping).