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A new Diagnostic Fracture Injection Test (DFIT) procedure and analysis method was recently introduced whereby flowback data, obtained immediately after pump shut down, is analyzed for closure pressure (
The DFIT-FBA procedure consists of two steps: 1) injection at about 3 to 6 bbls/min to initiate and propagate a mini hydraulic fracture and 2) immediate flowback of the injected fluid on surface at less than 5% of the injection rate using a choke management system. The well flowing pressure and flowback rates are monitored throughout the flowback period. Rate-transient analysis (RTA) methods are then applied to the flowback rates and pressures, including flow-regime identification plots to identify flow regimes and estimate reservoir pressure, and straight-line analysis to derive mini-fracture and reservoir properties. A unique set of field trials of DFIT-FBA are presented where vertical layers in the frontier unconventional reservoirs of the Beetaloo Basin are tested for
The DFIT-FBA procedure was successfully implemented for this exploration program. Flow regimes observed during the tests included before-closure wellbore/fracture storage and after-closure linear flow and boundary-dominated flow (BDF). Reservoir pressure (
This work engages both the completions and reservoir engineering communities. The results can be used for hydraulic fracture stimulation treatment design and for predicting the production performance of the reservoir.
A technique based on a simple compressibility equation and a mass balance equation has been developed that allows accurate determination of fracture volume and closure pressure. This new technique may help resolve the controversial determination of when a fracture closes. Through the graphical representation of this technique, knowledge of the fracture closure mechanism has been gained and presented in this paper.
The presented technique may be applied to either microfracture or minifracture tests. It may be applied to a pumpin/flowback test (microfracture) or be pumpin/flowback test (microfracture) or be coupled with the conventional minifracture analysis technique for application to pumpin/shut-in tests. pumpin/shut-in tests. The new technique is illustrated in this paper through its application to actual field cases. In the first field case, it is applied to a microfracture test (pumpin/flowback) performed on a shale formation. The technique clearly identified the closure pressure of the fracture and the fracture pressure of the fracture and the fracture volume, and fluid efficiency was calculated using an iterative scheme. In the second example, the technique was applied to a minifracture test (pump-in/shut-in).
The chief technical contributions of this paper may be summarized as follows:
1. A simple new technique is presented for determining fracture volume and closure pressure. 2. Through the graphical representation and application of the new technique, a better understanding of the closure mechanism has been achieved. 3. This technique determines fracture closure pressure with a fairly high degree of certainty.
During the last few years, the use of a fracturing test prior to the main fracturing treatment has significantly increased. These two tests are microfrac and minifrac tests. Both of these two tests are designed to give specific information about the fracture and/or fluid performance. A microfrac is a test in which one to two bbls of fluid are injected into the formation at a rate ranging from 2 to 20 gal/min. The rate and volume necessary to initiate and propagate a fracture for 10 to 20 ft depend on formation and fracturing fluid properties. Microfracturing tests were performed using many types of fluid, ranging from drilling fluid to gelled fluid. The main purpose of a microfracture is to measure the minimum principle stress. principle stress. Minifractures, on the other hand, are performed using the same type of fluid and performed using the same type of fluid and injection rate as will be used in the fracture treatment. A minifracture test is performed to determine leakoff coefficient performed to determine leakoff coefficient and fracture geometry. In this paper, application and analysis of microfracture and minifracture tests are discussed. A new and simple technique to analyze data from microfractures and minifractures is presented. This technique uses the existing presented. This technique uses the existing minifracture analysis method.
Summary We propose a novel method for estimating average fracture compressibility during flowback process and apply it to flowback data from 10 multifractured horizontal wells completed in Woodford (WF) and Meramec (MM) formations. We conduct complementary diagnostic flow-regime analyses and calculate by combining a flowing-material-balance (FMB) equation with pressure-normalized-rate (PNR)-decline analysis. Flowback data of these wells show up to 2 weeks of single-phase water production followed by hydrocarbon breakthrough. Plots of water-rate-normalized pressure and its derivative show pronounced unit slopes, suggesting boundary-dominated flow (BDF) of water in fractures during single-phase flow. Water PNR decline curves follow a harmonic trend during single-phase- and multiphase-flow periods. Ultimate water production from the forecasted harmonic trend gives an estimate of initial fracture volume. The estimates for these wells are verified by comparing them with the ones from the Aguilera (1999) type curves for natural fractures and experimental data. The results show that our estimates (4 to 22×10psi) are close to the lower limit of the values estimated by previous studies, which can be explained by the presence of proppants in hydraulic fractures.
In this study, we propose a new method for estimating average fracture compressibility
We observe two production signatures during flowback: (1) single-phase water production followed by hydrocarbon breakthrough and (2) immediate production of hydrocarbon with water. Water rate-normalized-pressure plots show pronounced unit slopes, suggesting pseudo-steady state flow. Water decline curves follow a harmonic trend during multiphase flow; from which we forecasted ultimate water production as an estimate of initial fracture volume. The
Abstract Tight reservoirs stimulated by multistage hydraulic fracturing are commonly characterized by analyzing the hydrocarbon production data. However, analyzing the available hydrocarbon production data mainly determines the fracture-matrix interface. This analysis is not enough for a full characterization of the induced hydraulic fractures. Before putting the well on flowback, the induced fractures are occupied by the compressed fracturing fluid. Therefore, analyzing the produced fracturing fluid should in principle be able to characterize the induced fractures, and complement the production data analysis. We develop a rate transient model for describing the fracturing fluid flowback. We also make various diagnostic plots for understanding the flowback behavior of three fractured horizontal wells. The diagnostic plots indicate three separate flowback regions. In the first region, water production dominates while in the third region hydrocarbon production dominates. In the second region, water production drops and hydrocarbon production ramps up. In general, we observe a linear relationship between rate normalized pressure (RNP) and material balance time (MBT) for the three regions. However, the proposed model can only describe the response of the first region. We successfully determine the hydraulic fracture permeability by history matching the early time flowback data. We conclude that the flowback analysis can complement the production data analysis for a comprehensive fracture characterization. The presented study encourages the industry to start careful measurement of the rate and pressure data immediately after putting the well on hydraulic fracture flowback.