SPE 169539 Diagnostic Fracture Injection Tests: Common Mistakes, Misfires, and Misdiagnoses R.D. Barree, J.L. Miskimins, and J.V. Gilbert, Barree & Associates Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Western North American and Rocky Mountain Joint Regional Meeting held in Denver, Colorado, USA, 16–18 April 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Over the last twenty years, Diagnostic Fracture Injection Tests, or DFIT’s, have evolved into commonly used techniques that can provide valuable information about the reservoir, as well as hydraulic fracture treatment parameters. Thousands are pumped every year in both conventional and unconventional reservoirs. Unfortunately, many tests that are pumped provide poor or no results due to either problematic data acquisition or incorrect analysis of the acquired data. This paper discusses common issues and mistakes made while acquiring DFIT data. Guidelines on how to avoid these errors and secure the best possible data are provided including data resolution, pump rates, test duration, and fluid selection. Rules of thumb are provided to estimate the time required to reach fracture closure and establish stable reservoir transients for analysis. The last part of the paper addresses potential (and commonly observed) problems in the analysis of the DFIT. These issues can be magnified in tight gas and shale reservoirs due the long data acquisition times and the subtle pressure transients that can occur. Specific issues that are discussed include poor ISIP data from perforation restriction, loss of hydrostatic head, gas entry and the resulting phase segregation, the use of gelled fluids, and errors in after closure analysis. Introduction Diagnostic fracture injection tests or DFIT’s are small pump-in treatments performed to gather data to help design follow-up hydraulic fracturing treatments, as well as to characterize the subject reservoir. DFIT’s have their basis in conventional mini- frac treatments; however, they are subtly different and are intended to acquire significantly more data for fracture design and execution and reservoir description. Conventional mini-frac treatments have historically been focused on acquiring very specific treatment design parameters, such as fluid efficiencies and leakoff values, however, DFIT’s are intended to expand that role and acquire additional data such as reservoir pore pressure, detailed closure and fracture gradients, process zone stresses (PZS), transmissibility values which can be converted into reservoir permeability values, and leak-off mechanisms. The advent of unconventional reservoirs have added even more value to DFIT testing, as most of the information gained is comparable to traditional pressure transient tests, which are impractical to run in tight sand and shale systems since the time to analyzable pseudo-radial flow can be months, if not years. A generic DFIT test is shown in Figure 1. The wellbore is first filled at low to moderate rate, until a positive surface pressure response is observed. With low to moderate wellbore compressibility, the pressure should rise quickly until initial breakdown occurs. Breakdown will either be indicated by a sharp drop in pressure as a new fracture initiates (as at point 1 in Figure 1), or a plateau in pressure as existing fractures are opened and extended. Once a breakdown event is observed, the injection rate should be increased to the maximum rate allowed by available horsepower, or to 75% of the planned treatment rate of the main frac, whichever is achievable. A constant rate is then held for 3-5 minutes (step 2 in Figure 1), after which a rapid step-down can be conducted. The step-down test is separate from the actual DFIT but is commonly run at the end of the pump-in to determine perforation and near-wellbore frictional pressure losses. The rate is then immediately reduced to zero, to obtain the instantaneous shut-in pressure (ISIP, shown as step 4) and the falloff pressure is monitored for as long as possible or as long as necessary to acquire the desired data. Even when high friction is not expected, the step-down is recommended to make identification of ISIP easier. More specific details of how to pump DFIT tests and recommended acquisition procedures are discussed later in this paper.