Characterizing natural fractures productivity in tight gas reservoirs

Journal of Petroleum Exploration and Production Technology, Jul 2012

Tight formations normally have production problems mainly due to very low matrix permeability and various forms of formation damage that occur during drilling completion and production operation. In naturally fractured tight gas reservoirs, gas is mainly stored in the rock matrix with very low permeability, and the natural fractures have the main contribution on total gas production. Therefore, identifying natural fractures characteristics in the tight formations is essential for well productivity evaluations. Well testing and logging are the common tools employed to evaluate well productivity. Use of image log can provide fracture static parameters, and welltest analysis can provide data related to reservoir dynamic parameters. However, due to the low matrix permeability and complexity of the formation in naturally fractured tight gas reservoirs, welltest data are affected by long wellbore storage effect that masks the reservoir response to pressure change, and it may fail to provide dual-porosity dual-permeability models dynamic characteristics such as fracture permeability, fracture storativity ratio and interporosity flow coefficient. Therefore, application of welltest and image log data in naturally fractured tight gas reservoirs for meaningful results may not be well understood and the data may be difficult to interpret. This paper presents the estimation of fracture permeability in naturally fractured tight gas formations, by integration of welltest analysis results and image log data based on Kazemi’s simplified model. Reservoir simulation of dual-porosity and dual-permeability systems and sensitivity analysis are performed for different matrix and fracture parameters to understand the relationship between natural fractures parameters with welltest permeability. The simulation results confirmed reliability of the proposed correlation for fracture permeability estimation. A field example is also shown to demonstrate application of welltest analysis and image log data processing results in estimating average permeability of natural fractures for the tight gas reservoir.

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Characterizing natural fractures productivity in tight gas reservoirs

Hassan Bahrami 0 Reza Rezaee 0 Mofazzal Hossain 0 0 H. Bahrami (&) R. Rezaee M. Hossain Department of Petroleum Engineering, Curtin University , Level 6, ARRC, 26 Dick Perry Ave, Kensington, Perth 6151, Australia Tight formations normally have production problems mainly due to very low matrix permeability and various forms of formation damage that occur during drilling completion and production operation. In naturally fractured tight gas reservoirs, gas is mainly stored in the rock matrix with very low permeability, and the natural fractures have the main contribution on total gas production. Therefore, identifying natural fractures characteristics in the tight formations is essential for well productivity evaluations. Well testing and logging are the common tools employed to evaluate well productivity. Use of image log can provide fracture static parameters, and welltest analysis can provide data related to reservoir dynamic parameters. However, due to the low matrix permeability and complexity of the formation in naturally fractured tight gas reservoirs, welltest data are affected by long wellbore storage effect that masks the reservoir response to pressure change, and it may fail to provide dual-porosity dual-permeability models dynamic characteristics such as fracture permeability, fracture storativity ratio and interporosity flow coefficient. Therefore, application of welltest and image log data in naturally fractured tight gas reservoirs for meaningful results may not be well understood and the data may be difficult to interpret. This paper presents the estimation of fracture permeability in naturally fractured tight gas formations, by integration of welltest analysis results and image log data based on Kazemi's simplified model. Reservoir simulation of dual-porosity and dual-permeability systems and sensitivity analysis are performed for different matrix and fracture parameters to understand the relationship between natural fractures parameters with welltest permeability. The simulation results confirmed reliability of the proposed correlation for fracture permeability estimation. A field example is also shown to demonstrate application of welltest analysis and image log data processing results in estimating average permeability of natural fractures for the tight gas reservoir. - A naturally fractured reservoir is mainly a network of natural fractures and matrix which are randomly distributed. Characterization of the natural fractures generally includes estimating the dynamic parameters such as fracture permeability, and determining the static parameters such as fracture spacing (matrix block size), fracture aperture and fracture porosity (Racht and Golf 1982). The most common geometrical representations of fractured reservoirs are the models introduced by Warren-Root and Kazemi as shown in Fig. 1, assuming that discrete matrix blocks are separated by an orthogonal system of continuous and uniform fractures. The matrix blocks are assumed to be isotropic and homogeneous identical rectangular parallelepipeds with no direct communication between them (Kazemi et al. 1976). The simplified models have been introduced to simulate flow through naturally fractured reservoirs. The double porosity domain assumes a continuous uniform fracture network oriented parallel to the principal axes of permeability. In many of the naturally fractured reservoirs, fracture permeability can be the major controlling factor of the flow of fluids. Fracture permeability in a dual-porosity and dualpermeability reservoir is the permeability that is associated with the secondary porosity created by open natural fractures (Racht and Golf 1982). The main dynamic parameters commonly used to describe matrix and interconnecting fracture network are interporosity flow coefficient (k) and fracture storativity ratio (x) that are defined as follows (Tiab et al. 2006): Fig. 1 Dual porositydual permeability system (Warren-Root and Kazemi simplified models) Naturally fractured reservoirs Tight gas reservoirs Where Km is matrix permeability, Kf is fracture permeability, rw is wellbore radius, uf is fracture porosity, um is matrix porosity, Cf is fracture compressibility, Cm is matrix compressibility, and d is shape factor and it is defined as follows: d 4 1 a2X 1 a2Y 1 a2Z 3 In Eq. (3), ax, ay and az are matrix block size respectively in x, y and z directions (Reiss 1980). In the case of Kazemi model (ax az and ay az), the shape factor, d, is considered to be 4 a2. The smaller value of k (higher fracture permeability) and/or the larger value of x (higher fracture porosity) result in higher well productivity. The dual-porosity and dual-permeability reservoirs dynamic parameters can be estimated using welltest analysis. As illustrated in Fig. 2, a Semi-Log plot of pressure build-up data results in two parallel lines, which the slope gives average permeability, the vertical separation between the parallel lines (DPx) can provide frac (...truncated)


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Hassan Bahrami, Reza Rezaee, Mofazzal Hossain. Characterizing natural fractures productivity in tight gas reservoirs, Journal of Petroleum Exploration and Production Technology, 2012, pp. 107-115, Volume 2, Issue 2, DOI: 10.1007/s13202-012-0026-x