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Abstract This paper outlines methods to characterize hydraulic fracture geometry and optimize full-scale treatments using knowledge gained from Diagnostic Fracture Injection Tests (DFITs) in settings where fracturing pressures are at or above the overburden gradient. Hydraulic fractures, whether created during a DFIT or a larger scale treatment, are usually represented by vertical plane fracture models. These models work well in a relatively normal stress regime with homogeneous rock fabric where fracturing pressure is less than the Overburden (OB) pressure. However, many hydraulic fracture treatments are pumped above the OB pressure. This high pressure may be caused by near well friction or tortuosity but may also be the result of more complex fractures in multiple planes. Bachman et al (2012, 2015), Hawkes et al (2018) and Nicholson et al (2019) advanced DFIT analysis by using the Pressure Transient Analysis (PTA) technique. This allows the identification of flow regimes useful for understanding fracture geometry and closure behavior beyond that available from more familiar G-function analysis techniques. In this paper DFITs from the Duvernay, Montney, Rock Creek and Cardium formations of Western Canada are analyzed using the PTA method. Particular attention is given to Early-Time Flow Regimes (ETFRs) present between the end of pump shut-down (End of Job Instantaneous Shut-In Pressure, EOJ ISIP) and the 3/2-slope Nolte flow regime. Identification of pressure gradients at the start and end of these flow regimes is of vital importance to the interpretation process. This allows the authors to build on case histories of DFIT-derived fracture geometry interpretations presented in Nicholson et al (2017, 2019). Procedures are proposed for picking Farfield Fracture Extension Pressure (FFEP) in place of conventional IIP estimates while distinguishing between storage, friction and tortuosity vs. fracture geometry indicators. Analysis of FFEP and ETFRs combined with the context of rock fabric and stress setting are useful for designing full-scale fracturing operations. A DFIT may help identify potentially problematic multi-plane fractures, predict high fracturing pressures or screen-outs. Fluid and completion system designs, well placement and orientation may be adjusted to mitigate some of these effects using the intelligence gained from the DFIT early warning system.
Analysis of mini-frac or, as commonly referred to in North America, Diagnostic Fracture Injection Tests (DFITs), have traditionally been the sub-discipline of completion & hydraulic fracture stimulation engineers. Conducting such tests has direct and indirect costs resulting from the test itself and the extended time required for the pressure falloff, that delays the completion of the well. The benefits must therefore outweigh the costs if the test is to be justified. The value is evident as these tests are performed regularly around the world as it is one of only a few processes that can help quantify within the same test both geomechanical properties and reservoir performance drivers.
The authors will present examples and lessons learned from regions around the world. In addition, the availability of a large quantity of public, high-quality data from oil & gas operators in Western Canada operating in shale and ultra-tight formations enable an assessment of the successes and failures of wellbore completions, reservoir types, and operator procedures. This treasure-trove of data will help completion engineers regardless of their basin of operations to overcome one of industries challenging questions "did the test achieve its objectives."
Abstract A method has been developed for the analysis of pressure falloff data following a single-stage treatment in a multi-stage fracture stimulation. The basic premise is that the greater the permeability contacted by the fracture stimulation, the greater the rate of pressure falloff will be. This can be done with as little as 15 minutes of falloff data, but with a “zipper” style completion, the surface pressure falloff of a given fracture stage may be monitored for several hours for no incremental cost while an offset well on the same pad is being stimulated. The initial falloff data is collected well before fracture closure, so proppant is not yet a factor – the pressure decay is influenced by the total fracture system of that stage. This analysis has been performed on approximately 30 wells, each with about 20 stages, including two wells equipped with fiber optic sensing. The pressure decay follows a straight line on a plot of pressure versus logarithm of time. The slope of that line is the decay exponent, and a large exponent is indicative of greater connected permeability or fracture complexity. The development of this technique is in its early phases, but thus far a good correlation has been observed between the pressure decay exponent and microseismic activity, as well as between pressure decay and the Young's modulus of the rock being stimulated. In a multi-cluster “plug and perf” completion equipped with fiber optic cable, a positive correlation was observed with the number of clusters being treated. When the same hydraulic fracture stimulation was executed in similar rock types, very consistent results were obtained, suggesting a valid and repeatable relationship. The final validation of this technique will be possible when compared against production logging results. The prospect of a low cost, or even free, analytical technique in an environment where anything beyond a gamma ray curve is often a luxury, is particularly exciting. This assessment technique could be used for optimization of perforation cluster design and location, landing zone, and fracturing fluid optimization. The authors invite other operators to try this technique and discuss their observations.
Abstract This paper will benefit engineers and geoscientists interested in creating representative hydraulic fracture simulation models and optimizing commercial-scale fracture treatments. The paper focuses on the emerging Duvernay shale formation in Alberta, Canada. Well fracturing pressures are often significantly higher than the Overburden (OB, lithostatic) pressure. Pressures above OB likely create horizontal (hz) bedding plane fracture components since sedimentary rocks are almost always weaker along bedding planes. Most fracture design simulators do not account for the simultaneous existence of multi-plane fractures (Figure 1). Therefore, scaled treatment designs for optimizing fluids, proppant schedules and production performance may be flawed. A key question is: What proportion of the overall fracture volume do horizontal-plane features take? The answer can be sought using the Pressure Transient Analysis (PTA) workflow for Diagnostic Fracture Injection Tests (DFITs) described by Bachman et al (2012, 2015) combined with simple PKN and GDK fracture models to represent the hz and vertical plane fracture components. DFIT analysis techniques and interpretation are hotly debated topics of late. The authors believe a portion of the gap in the understanding of how hydraulic fractures behave is a result of assuming fracture components are fully, or dominantly, vertical. Analysts often interpret high fracturing pressures as tortuosity or near-well friction. However, during the fall-off period after pumping a DFIT, pressures above OB can persist for up to 20 minutes after pump shut-down. Analysis of these tests often exhibit early-time radial flow signatures which are coincident with the OB gradient of ~22kPa/m (1psi/ft) also indicative of hz plane fractures. In Nicholson et al 2017 four field DFIT examples were presented showing strong evidence of hz plane fractures in various depths and formations found in the Western Canadian Sedimentary Basin. In the current paper DFIT PTA analysis is applied to two West Shale Basin Duvernay datasets. A physical model is presented (Figure 1) that incorporates the in-situ stress regime, rock fabric, and pore pressure and that allows history matching of DFIT leak-off and closure behavior for fractures above OB pressure. Simple calculations are provided to estimate the volume and dimensions of these same components for a small volume, single viscosity, no-proppant injection DFIT. This unique approach provides a valuable calibration point for building more advanced simulation models.
Ehlig-Economides, Christine (University of Houston) | Bychina, Mariia (University of Houston / DeGolyer and MacNaughton) | Liu, Guoqing (University of Houston) | Wang, Jie (University of Houston / Stratum Reservoir)
Very low permeability prevents the use of conventional formation or buildup tests for permeability estimation. The Diagnostic Fracture Injection Test (DFIT) offers a way to estimate permeability using the after closure (AC) transient response, but the time to reach a meaningful AC transient may extend to many hours or days, or may never appear. This paper introduces a new model showing that miscible fluid injection produces a linear flow response in the early BC DFIT falloff transient that is easily recognized on a Bourdet log-log diagnostic plot as a pressure derivative trend with 1/2 slope appearing after less time than the injection time duration, which is frequently about 10 minutes. From this before closure trend the reservoir permeability can be straightforwardly estimated.
This study was motivated by appearance of BC apparent linear flow in some field DFITs conducted by injecting reservoir fluid. To explain the BC behavior, we formulated a model that accounts for three pressure drops across the filter cake, filtrate and reservoir zones extending in the direction perpendicular to the created fracture face.
The model demonstrates that BC linear flow behavior happens when no filter cake forms and when flow near the fracture face is miscible. In this case the pressure drop in the reservoir zone dominates, and the low permeability of the formation controls the leakoff process. There are other scenarios when the reservoir pressure drop dominates, but miscible injection guarantees this behavior. Because miscible fluid may not be the designated fluid for the hydraulic fracture treatment, the miscible fluid DFIT will not provide the treatment fluid leakoff coefficient. However, the obtained value of reservoir permeability may balance this limitation. This paper provides a miscible fluid DFIT design that enables estimation of reservoir permeability, as well as wellbore, perforation, and near wellbore friction losses and closure pressure. We also show analysis workflow for the suggested test design.
Reservoir permeability is a critical parameter for hydraulic fracture design and especially for optimizing the perforation cluster spacing in multiple transverse fracture horizontal wells. The miscible fluid DFIT enables permeability estimation from the early time portion of the BC falloff transient, and does not require waiting until closure time or for the AC response. Because the AC response is frequently distorted, and abnormal closure behavior is common, this test offers a more reliable permeability estimation.