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Zeinabady, Danial (University of Calgary) | Zanganeh, Behnam (University of Calgary, Chevron Canada Resources) | Shahamat, Sadeq (Birchcliff Energy Ltd.) | Clarkson, Christopher R. (University of Calgary)
Abstract The DFIT flowback analysis (DFIT-FBA) method, recently developed by the authors, is a new approach for obtaining minimum in-situ stress, reservoir pressure, and well productivity index estimates in a fraction of the time required by conventional DFITs. The goal of this study is to demonstrate the application of DFIT-FBA to hydraulic fracturing design and reservoir characterization by performing tests at multiple points along a horizontal well completed in an unconventional reservoir. Furthermore, new corrections are introduced to the DFIT-FBA method to account for perforation friction, tortuosity, and wellbore unloading during the flowback stage of the test. The time and cost efficiency associated with the DFIT-FBA method provides an opportunity to conduct multiple field tests without delaying the completion program. Several trials of the new method were performed for this study. These trials demonstrate application of the DFIT-FBA for testing multiple points along the lateral of a horizontal well (toe stage and additional clusters). The operational procedure for each DFIT-FBA test consists of two steps: 1) injection to initiate and propagate a mini hydraulic fracture and 2) flowback of the injected fluid on surface using a variable choke setting on the wellhead. Rate transient analysis methods are then applied to the flowback data to identify flow regimes and estimate closure and reservoir pressure. Flowing material balance analysis is used to estimate the well productivity index for studied reservoir intervals. Minimum in-situ stress, pore pressure and well productivity index estimates were successfully obtained for all the field trials and validated by comparison against a conventional DFIT. The new corrections for friction and wellbore unloading improved the accuracy of the closure and reservoir pressures by 4%. Furthermore, the results of flowing material balance analysis show that wellbore unloading might cause significant over-estimation of the well productivity index. Considerable variation in well productivity index was observed from the toe stage to the heel stage (along the lateral) for the studied well. This variation has significant implications for hydraulic fracture design optimization, particularly treatment pressures and volumes.
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.
Zhang, Z. (University of Calgary) | Yuan, B. (University of Calgary) | Ghanizadeh, A. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Williams-Kovacs, J. D. (University of Calgary)
Abstract The application of rate-transient analysis (RTA) concepts to flowback data gathered from multi-fractured horizontal wells (MFHWs) completed in tight/shale reservoirs has recently been proposed as an independent method for quantitatively evaluating hydraulic fracture properties. However, the initial fluid pressures and saturations in the fracture network, and adjacent reservoir matrix, are generally unknown at the start of flowback, creating significant uncertainty in the quantitative analysis of flowback data. A possible approach to recreate these initial conditions is to simulate fluid leakoff during hydraulic fracture propagation (during the stimulation treatment) and subsequent shut-in period prior to flowback. In this study, we present a semi-analytical flow model, coupled with a hydraulic fracture (‘frac’) model and constrained with laboratory-based geomechanical data, for evaluating the initial conditions of flowback. In previous work, a semi-analytical model based on the dynamic drainage area (DDA) concept was used to simulate water-based fluid leakoff from a MFHW into a tight oil reservoir with minimal mobile water (Montney Formation) in Western Canada during and after fracturing operations. The model assumes that each fracturing stage can be represented by a primary hydraulic fracture (PHF, containing the majority of the proppant), and adjacent non-stimulated reservoir (NSR) or enhanced fracture region (EFR, area of elevated permeability in reservoir caused by the stimulation treatment). Each region was represented by a single-porosity system. The DDA propagation speed within the PHF during the stimulation treatment was constrained through the use of a simple analytical frac model. While this approach was considered novel, several improvements, and additional laboratory constraints, were considered necessary to yield more accurate predictions of flowback initial conditions. In the current work, the modeling approach described above was improved byrepresenting the EFR with a dualporosity system and fully coupling the frac model (used for PHF creation and propagation) with the DDA model for fluid leakoff simulation into the EFR. Improvement 1) was considered necessary to more realistically represent the spatial distribution of fluids in the EFR and associated saturations and pressures. Improvement 2) was considered necessary to more realistically control PHF propagation speed. Finally, to ensure that model geomechanics were properly constrained, a comprehensive suite of previously-gathered laboratory data was utilized. Laboratory-derived propped (PHF) and unpropped (EFR) fracture permeability/conductivity data as a function of pore pressure, as well as fracture compressibility data, were used as constraints to the model. The improved model was re-applied to the tight oil field case and yielded more realistic estimates of flowback initial conditions, enabling more confident history-matching of flowback data. The results of this study will be of importance to those petroleum engineers interested in quantitative analysis of flowback data to accurately obtain fracture properties by ensuring that models are properly initiated.
Ziarani, Ali S. (Trican Well Service Ltd.) | Chen, Cheney (Trican Well Service Ltd.) | Cui, Albert (Trican Geological Solutions) | Quirk, David James (Trican GeoTomo Microseismic) | Roney, Dana (Lone Pine Resources)
Abstract Horizontal wellbore drilling and completion technology with multi-stage fracturing has revolutionized the exploitation of unconventional resources in North America in recent years. Many unconventional oil and gas reservoirs with ultra-low permeability have become economical as a result. Yet, the development and completion costs of these resources can be further improved by optimizing the number of fracture stages placed on each wellbore and the number of wellbores drilled per section of land. This study highlights our operational and analytical experience on an integrated workflow for optimization of fracture and wellbore spacing to develop the unconventional resource in Western Canadian Sedimentary Basin. The study is based on fracturing design and optimization, microseismic fracture mapping, reservoir modeling and production analysis for over 30 case studies on different formations in Canada including Montney, Cardium, Doig, Beaverhill Lake, Viking, and Sprit River formations. The typical workflow for fracture and well spacing optimization studies includes multiple and iterative steps: minifrac tests, fracture modeling and calibration, fracture job execution, microseismic monitoring, reservoir simulation and production data analysis. In this integrated process, hydraulic fracture models were built based on fracture job data, rock mechanics and log data, and then calibrated with minifrac data and microseismic fracture mapping results. Three dimensional reservoir simulation models were constructed using laboratory core data, petrophysical and geological data, and reservoir fluid PVT properties. The calibrated fracture models were integrated into reservoir simulation models. The reservoir models were fine-tuned by history matching the production data. The fine-tuned models were then used to run multiple scenarios by varying the number of fracturing stages per wellbore and wellbores per section. Fracturing treatments with different pump rate, proppant size, pumping schedule and proppant tonnage were further investigated to optimize fracture geometry and conductivity for production enhancement. Optimal fracture and wellbore spacing scenarios were recommended for future drilling and completion planning in the field. Such optimization studies have helped to minimize operation cost and improve the economics of resource development. Our workflow and experience in West Western Canadian Sedimentary Basin can be a useful guideline to improve economic success of unconventional resources in other basins around the world.