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    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 inject ion 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 co nventional 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 desig n 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.  2 SPE 169539 Figure 1: Generic DFIT procedure. Initial breakdown is achieved at point 1; a constant rate is held for 3-5 minutes indicated by point 2; point 3 shows a rapid step-down; point 4 indicates ISIP; and point 5 shows falloff. This paper not intended to provide specific instructions on the basics of how to analyze DFIT tests, as that information is described in detail in other papers (Barree, et al, 2009; Barree, 1998). Rather, as the title implies, it aims to aid in the acquisition of useful and analyzable data, as well as provide hints to common problems that occur either during the pumping of the test or during the analysis of the results. It is not uncommon to hear statements that disparage the test, however, most of the problems can be attributed to failed tests that do not provide any useful data because they were pumped or analyzed incorrectly. This is a valid concern  –   these tests cost additional time and money, and if they fail to provide usable information value is lost or destroyed. However, more often than not, it is the quality of the acquired data and how the acquisition does (or does not) take place that is the root issue. If appropriate steps are taken and quality data acquired, the tests are quite valid and correct interpretation can shed light on what the reservoir is trying to say. This paper tries to address these acquisition issues, provide guidance on acquiring quality data, and discuss some common mistakes that happen during analysis procedures. If these steps are addressed, the success rate of the treatments should increase significantly. Most of the examples in this paper focus on unconventional, tight hydrocarbon systems, however, all  points are equally applicable to conventional reservoirs. Recommended Acquisition Procedure Every time fluid is pumped into a formation, there is a risk of formation damage. Therefore, fluid injections of any kind should be minimized and be conducted under controlled conditions. However, at the same time, enough fluid must be injected under fracturing conditions to adequately contact the reservoir and provide conditions under which the desired  parameters can be measured. A DFIT is a fracture test, and must be conducted at a stable fracturing rate. It does not take extremely high rates to initiate and propagate a fracture in low to moderate permeability formations. In milli-Darcy range permeabilities, rates of 1-2 BPM are frequently high enough to exceed fracturing pressure. Approximate rates that cause fracture extension in a given situation can be calculated using radial Darcy’s Law , as shown in Equation 1. To extend a fracture the injection rate must be high enough to generate a pressure differential (   p safe ) greater than the net fracture extension pressure, FG*D-p. For micro- and nano-Darcy systems, the necessary rates are even lower. Figure 2 shows a graph relating the generated  pressure for a variety of reservoir permeabilities. In an effort to pump enough fluid to adequately contact the reservoir, do so in a relatively short amount of time, and provide a safety factor, rates of 5-6 BPM, or even slightly higher, 7-8 BPM, have  proven to be very successful in providing good results. This maximum rate is recommended to be held for 3-5 minutes, as shown in Figure 1, which results in ~600-1800 gallons of fluid being injected. )(ln])*[(10917.4  6max,  sr r  p p D FGkh X  q we safei      (1)  SPE 169539 3 Where, q i,max = injection rate in bbl/min k = permeability of undamaged formation, md h = net thickness, ft FG = fracture gradient, psi/ft D = depth, ft Δp safe  = safety margin, psi  p = reservoir pressure, psi μ = viscosity of injected fluid, cp β = formation volume factor r  e  = drainage radius, ft r  w  = wellbore radius, ft s = skin Figure 2: Rate necessary to initiate a fracture at various reservoir permeabilities. Assumes a reservoir depth of 7000 ft, fracture gradient of 0.8 psi/ft, normal hydrostatic pore gradient, formation thickness of 20 ft, and a water fluid system.  Data resolution for the entire injection and falloff period is a critical component. Common pumping gauge resolutions of 5-10 psi are not adequate for DFIT acquisition, since the intent of the treatment is look for subtle variations in the derivative of the pressure versus time. Low resolution gauges can miss these data and render the test unusable. It is recommended to use gauges that have a resolution of at least 0.01  –   0.10 psi, with a sampling rate of one measurement per second during the  pumping period and through fracture closure. This sampling rate can then be expanded during the falloff period after closure. During the post-closure falloff period, a sampling rate of up to one measurement every 30 seconds is adequate and achievable with appropriate gauge memory systems. Two key parameters in the analysis of a DFIT is the time and volume of injection (Barree, et al, 2009; Barree, 1998), therefore, the injection schedule must be recording precisely. Ideally, it is measured digitally in conjunction with the pressure during the injection period, however, if this is not possible or is not done, extremely detailed notes must be kept that detail the pumping start/stop times and any rate changes and times of such made during the procedure. If the data are recorded in detail, a rate schedule can then be recreated during analysis. Fluid selection for the treatment is a common question  –   what is the best option? In general, a Newtonian, non-wall  building fluid should be used. This is one area that differs significantly from traditional mini-fracs, which commonly inject gelled or other non-Newtonian fluid systems, specifically to measure fluid efficiency. For DFIT purposes, water, diesel, or some other type of non-wall building fluid should be used. The reason for this is demonstrated by Figures 3-5. Figure 3 demonstrates the conventional fluid loss model as a one-dimensional solution for linear transient flow with constant pressure  boundary conditions. The fluid pressure at the fracture face is assumed constant with time and the far-field pore pressure is assumed to be constant. Initially the pressure gradient, and the associated leakoff rate, is very high. With time, the transient moves further into the reservoir and the gradient (and rate) decrease. This solution shows rate decreasing linearly with the square-root of time. 0.0000010.000010.00010.0010.010.11101000.00010.0010.010.11101001000 Permeability (md) Rate(BPM)  4 SPE 169539 Figure 4 then shows leakoff modeled as a combination of series flows. The figure roughly describes a high permeability far-field reservoir zone, a near-fracture invaded zone, and a thin wall filter-cake zone. In series flow, the total pressure drop through the system is the sum of the pressure drops through each zone. Using Darcy’s Law  in linear fashion, each pressure drop can be determined from the length and permeability of each zone. When even a thin film of very high flow resistance is  present, such as the filter-cake, the flow capacity of the least conductive region dominates the system. When this filter-cake is deposited on a fracture wall, as demonstrated in Figure 5, most of the pressure drop is taken across the filter-cake during leakoff. The far-field pressure gradient is much less than expected when computed based on the leakoff rate, and the after-closure analysis yields an estimate of reservoir flow capacity, i.e. kh, that is much too high and is inconsistent with the observed closure time. Figure 3: Conventional fluid loss model as a one-dimensional solution for linear transient flow with constant pressure boundary conditions. Figure 4: Leakoff modeled as a combination of series flows for permeabilities of 100 md, 1 md, and 0.001 md. Figure 5: When a filter-cake is deposited on a fracture wall most of the pressure drop is taken across the filter-cake during leakoff unlike that shown in Figure 3 which demonstrates the pressure drop in an undamaged system. As a last acquisition component, isolation of the wellhead after pumping ends is required in order to eliminate any inadvertent pressure transients that might be caused by mechanical or logistical issues. Since DFIT analysis uses derivatives, any large changes or “bumps” in press ure, can inadvertently alter, invalidate the test, or render it impossible to analyze. Any  pressure bleedoff that might occur during rig-down can render the test useless. Likewise, if pressure measurements are being

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