Figure 1 A schematic of a numerical simulation model. (Horizontal well with multiple transverse — fractures) Table 1 shows a summary of the model input parameters. Table 1 Reservoir and fluid properties for simulated horizontal shale gas well model with multiple — transverse fractures. Reservoir Properties: Net pay thickness, = 130 ft h Formation permeability, = 0.25µD-5µD k Wellbore Radius, = 0.35 ft rw Formation compressibility, = 3 x 10-6 psi-1 cf Porosity, = 0.09 (fraction) Initial reservoir pressure, = 5000 psi pi Gas saturation, = 1.0 fraction sg Skin factor, = 0.01 (dimensionless) s Reservoir temperature, = 212 °F Tr Fluid properties: Gas specific gravity, = 0.6 (air = 1) γg Hydraulically fractured well model parameters: Fracture half-length, = 164.0 ft xf Number of fractures = 15 Horizontal well length = 4921.3 ft Production parameters: Flowing pressure, = 500 psia pwf Production time, = 10,958 days (30 years) t Fig. 2 and Fig. 3 shows a "qDb" type diagnostic plot of a time-rated data match using the PLE, LGM and Duong time-rate relations. The diagnostic relations will provide a systematic and data driven estimation of the model parameters. When there is no restriction on the degree of freedom, it is possible to obtain a wide range of parameters that result in a model fit. Figure 2 (Log-log Plot): type plot flow rate (qg), and parameter versus production time qDb D- b- — ─ and time-rate model (PLE, LGM, Duong) matches simulated case (k=800 nD) ─ Figure 3 (Log-log Plot): type plot flow rate (qg), and parameter versus production time qDb ─ D- b- — and time-rate model (PLE, LGM, Duong) matches simulated case (k=50 nD) ─ . Fig. 3 shows that the PLE model is capable of modeling all flow regimes including boundary dominated flow regimes whereas Duong and LGM time-rate relations match transient and transition flow regimes. Fig. 2 and Fig. 3 show that the new time-rate relations are capable of modeling the long transient flow regimes observed from unconventional reservoirs.
Figure 1 — A schematic of a numerical simulation model. (Horizontal well with multiple transverse fractures) Table 1 shows a summary of the model input parameters. Table 1 — Reservoir and fluid properties for simulated horizontal shale gas well model with multiple transverse fractures. Reservoir Properties: Net pay thickness, h = 130 ft Formation permeability, k = 0.25µD-5µD Wellbore Radius, rw = 0.35 ft Formation compressibility, cf = 3 x 10-6 psi-1 Porosity, = 0.09 (fraction) Initial reservoir pressure, pi = 5000 psi Gas saturation, sg = 1.0 fraction Skin factor, s = 0.01 (dimensionless) Reservoir temperature, Tr = 212 °F Fluid properties: Gas specific gravity, γg = 0.6 (air = 1) Hydraulically fractured well model parameters: Fracture half-length, xf = 164.0 ft Number of fractures = 15 Horizontal well length = 4921.3 ft Production parameters: Flowing pressure, pwf = 500 psia Production time, t = 10,958 days (30 years) Fig. 2 and Fig. 3 shows a "qDb" type diagnostic plot of a time-rated data match using the PLE, LGM and Duong time-rate relations. The diagnostic relations will provide a systematic and data driven estimation of the model parameters. When there is no restriction on the degree of freedom, it is possible to obtain a wide range of parameters that result in a model fit. Figure 2 — (Log-log Plot): qDb type plot ─ flow rate (qg), D- and b- parameter versus production time and time-rate model (PLE, LGM, Duong) matches ─ simulated case (k=800 nD) Figure 3 — (Log-log Plot): qDb type plot ─ flow rate (qg), D- and b- parameter versus production time and time-rate model (PLE, LGM, Duong) matches ─ simulated case (k=50 nD) . Fig. 3 shows that the PLE model is capable of modeling all flow regimes including boundary dominated flow regimes whereas Duong and LGM time-rate relations match transient and transition flow regimes. Fig. 2 and Fig. 3 show that the new time-rate relations are capable of modeling the long transient flow regimes observed from unconventional reservoirs.
20120915_Askabe_MS_Proposal.docx