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Clarkson, Christopher R. (University of Calgary) | Williams-Kovacs, Jesse (University of Calgary and Sproule Associated Limited) | Zhang, Zhenzihao (University of Calgary) | Yuan, Bin (University of Calgary) | Ghanizadeh, Amin (University of Calgary) | Hamdi, Hamidreza (University of Calgary) | Islam, Arshad (Baytex Energy Corp.)
Abstract Recently it has been demonstrated that rate-transient analysis (RTA) performed on flowback data frommulti-fractured horizontal wells (MFHWs) can provide timely estimates of hydraulic fracture properties. This information can be used to inform stimulation treatment design on upcoming wells as well as other important operational and development decisions. However, RTA of flowback data may be complicated by rapidly changing operating conditions, dynamic hydraulic fracture properties and multi-phase flow in the fractures, complex fracture geometry, and variable fracture and reservoir properties along the MFHW, among other factors. While some constraints on RTA model assumptions may be applied through a carefully-designed surveillance and testing program in the field (e.g. to constrain fracture geometry), still others require laboratory measurements. In this work, an integrated flowback RTA workflow, designed to reduce uncertainty in derived hydraulic fracture properties, is demonstrated using flowback data from MFHWs producing black oil from low-permeability reservoirs in the Montney and Duvernay formations. The workflow includes rigorous flow-regime identification used for RTA model selection, straight-line analysis (SLA) to provide initial estimates of hydraulic fracture properties, and model history matching of flowback data to refine hydraulic fracture property estimates. The model history matching is performed using a recently-introduced semi-analytical, dual-porosity, dynamic drainage area (DP-DDA) model that incorporates primary (propped) hydraulic fractures (PHF) as well as a dual-porosity enhanced fracture region (EFR) with an unpropped (secondary) fracture network. Inclusion of both the PHF and EFR components addresses the need to incorporate both propped and unpropped fractures and fracture complexity in the modeling. The DP-DDA model is constrained using estimates of propped fracture conductivity and unpropped fracture permeability (measured as a function of stress), and unpropped fracture compressibility values, obtained in the laboratory for Montney and Duvernay core samples. Use of these critical laboratory data serves to improve the confidencein the modeling results. The case studies provided herein demonstrate a rigorous workflow for obtaining more confident hydraulic fracture property estimates from flowback data through the application of RTA techniques constrained by both field and laboratory data.
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.
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
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.
Abstract In this study, we propose a new method for estimating average fracture compressibility during flowback process, and apply it on flowback data from thirty multi-fractured horizontal wells completed in Eagle Ford, Horn River, Montney and Woodford formations. We conduct complementary diagnostic flow regime analyses and calculate by combining a flowing material balance equation with rate-decline analysis. 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 estimates are within the range of 7 – 200 × 10 psi, and are generally lower than the values previously estimated using Aguilera’s type curves and DFIT data. Also, estimates for deeper dry gas wells are relatively higher than those for shallower oil wells.