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Abstract Minifrac/diagnostic fracture injection tests (DFITs) are an important and integral part of hydraulic fracture design and reservoir evaluation. Models for analysis of the before and after closure data have been developed. While several models exist and are being used to analyze the after closure data, before closure analysis (BCA) is not widely used, and only a handful of models have been developed. Additionally, the models are based on similar approaches and assumptions. This paper introduces a new BCA model based on rigorous treatment of the fluid flow equations in the fracture and the formation. In this new model, the assumptions of linear leakoff and short injection time for a minifrac test are made. In general, these assumptions are valid. In unconventional reservoirs, where permeability is expected to be very low, the assumption of linear leakoff is particularly valid and would last most of the duration of the before closure period. In most minifrac tests, the injection time is relatively small with respect to after shut-in time, which validates this new model assumption of short injection time. Fracture stiffness is a critical parameter when using this model, which can be easily calculated or measured from logging or experimental data. By using the before closure model presented here, formation permeability could be estimated by interpretation of the slope of straight line in the specialized Cartesian plot using before closure data. This paper details the development of the new model and compares it to existing models. In addition, several field examples from unconventional formations are presented and analyzed using various techniques, demonstrating the applicability of this new model. The results are also compared to the after closure analysis (ACA).
- North America > United States (1.00)
- North America > Canada > Alberta (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Mathematical Model for Stimulation of CBM Reservoirs During Graded Proppant Injection
Keshavarz, A.. (University of Adelaide) | Khanna, A.. (University of Adelaide) | Hughes, T.. (University of Adelaide) | Boniciolli, M.. (University of Adelaide) | Cooper, A.. (University of Adelaide) | Bedrikovetsky, P.. (University of Adelaide)
Abstract A modelling-based prediction of well productivity enhancement for recently developed technology for stimulation of natural fracture systems in CBM reservoirs is presented. The proposed technology can also be used for productivity enhancement of gas wells in other unconventional reservoirs, i.e., shales and tight gas reservoirs. Injection of proppant particles with increasing size and decreasing concentration results in deep percolation of proppant into the natural fracture system, expansion of the stimulated zone and increase of well productivity index. A modified mathematical model for well indices during graded particle injection, accounting for stress changes in coal beds, is developed. The model is based on analytical solution for quasi 1D problem with coupling of axisymmetric fluid flow and geomechanics. The results of previous computational fluid dynamic studies have been used to determine hydraulic resistance due to proppant placement in the fractured system. Explicit analytical equations were derived for stress, pressure and permeability distributions, as well as for the well index during injection and production. Results of previous computational fluid dynamics studies were used to determine the hydraulic resistance resulting from proppant plugging in the fractured system. By applying the effect of proppant concentration and fracture deformation, a critical stimulation radius is introduced beyond which proppant placement decreases coal permeability and well productivity index. This model has been applied for a real field case, and the effect of injection pressure on well productivity index and stimulation radius is presented. The results show significant increase in productivity index due to graded proppant injection in CBM reservoirs.
- North America > United States (0.46)
- Asia > China (0.28)
- Europe > Austria (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.68)
Stimulation of Unconventional Naturally Fractured Reservoirs by Graded Proppant Injection: Experimental Study and Mathematical Model
Keshavarz, Alireza (1Australian School of Petroleum, The University of Adelaide, Adelaide, Australia) | Badalyan, Alexander (1Australian School of Petroleum, The University of Adelaide, Adelaide, Australia) | Carageorgos, Themis (1Australian School of Petroleum, The University of Adelaide, Adelaide, Australia) | Johnson, Ray (1Australian School of Petroleum, The University of Adelaide, Adelaide, Australia) | Bedrikovetsky, Pavel (1Australian School of Petroleum, The University of Adelaide, Adelaide, Australia)
Abstract The coal permeability declines due to fracture closure during the production and pressure depletion. The recently proposed technique for stimulation of natural coal cleats consists of the injection of microsized high-strength particles into a coal natural fractured system below the fracturing pressure. Coupling this technique with hydraulic fracturing treatment resulted in particles entering cleats under leal-off condition. In the current paper it is shown that the particles must be deposited at specific conditions of the particle-coal repulsion, ensuring the absence of external cake formation. The new method was successfully validated through laboratory injection of microsized glass particles into fractured coal cores. Application of Derjaguin-Landau-Verwey-Overbeek (DLVO) theory resulted in determination of experimental conditions favourable for particle-particle and particle-coal repulsion; these conditions also immobilize the natural fines. At these conditions, no particle attachment to coal surface and no particle agglomeration were observed, thus the conditions exclude formation damage due to external cake formation, particle attraction to coal rock and fines migration. The previously developed mathematical model was used for determination of the duration of particle injection into a coal core at minimum effective stress. Particle placement resulted in almost three-time increase in coal permeability, thus confirming the mathematical model used. The curve for well productivity index-vs-stimulation zone radius reaches maximum at some critical value of stimulation radius; the maximum is determined by the mathematical model. Placing particles beyond this critical radius results in reduction of well productivity index, due to significant hydraulic losses experienced by suspension flowing through narrowing cleat apertures during production stage. Applying the proposed novel technology during hydraulic fracturing treatment leads to improvement in productivity of coal seam gas wells and other unconventional resources (shales, tight gas and geothermal reservoirs) through enhancement of interconnectivity among microfractures around the hydraulically induced fractures.
- Europe (1.00)
- Oceania > Australia (0.68)
- North America > United States > Texas (0.47)
- Research Report > New Finding (0.50)
- Research Report > Experimental Study (0.40)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.66)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract Recent advances in well design and production techniques have brought considerable attention to exploitation of tight (low permeability, absolute permeability <1 mD) oil resources. Drilling of long horizontal wells and deployment of hydraulic fractures along these wells (multi-fractured horizontal wells) can substantially improve the primary production rates from such reservoirs. Nevertheless, the low effective permeability of these reservoirs to oil hinders the sustainability of favorable oil rates and at some point applying some EOR technique becomes inevitable. In the current study, CO2 miscible flooding and WAG process in a tight oil reservoir are investigated. Although several studies have investigated different aspects of the process in conventional oil plays, the design of an effective scheme in tight oil formations is more complex. These complexities are related to the proper design of the fractures (half-length, conductivity, orientation (transverse vs. longitudinal), etc.) and their relative placement along producers and injectors and the operational constraints on each well or segment of the well. In this work, we utilize an EOR scheme design where multi-fractured horizontal wells are used for both injection and production, and the hydraulic fracturing stages are staggered to delay breakthrough and improve sweep efficiency. For a set of defined parameters, compositional simulations are conducted to investigate the effect of the CO2 slug size, WAG ratio and cycle length on the recovery efficiency of the model. The recovery from the aforementioned EOR process is then compared with its corresponding base case in which the reservoir has gone through periods of primary and water-flooding stages. The results of this study show that the incremental oil recovery from WAG process in tight formation can reach as high as 20%.
- North America > United States (0.94)
- North America > Canada > Alberta (0.30)
- Europe > Norway > Norwegian Sea (0.24)