Analysis of Multiple Flow/Buildup Tests Including a 5-year Buildup: Case Study of an Australian Shale Gas Well

Long-term (multiyear) buildup tests conducted for multifractured horizontal wells (MFHWs) completed in shale reservoirs offer the unique opportunity to study and analyze flow-regimes sequences that are not commonly observed with typical buildup test periods. In this study, two buildup periods (including a rarely observed, nearly 5-year buildup), and the preceding extended flow tests, were analyzed for an MFHW completed in an Australian shale gas reservoir within the Beetaloo Basin. The objectives of the analyses were to (a) identify the sequence of flow regimes observed for each test (flow/buildup, F/BU) period; (b) extract estimates of reservoir permeability and hydraulic fracture properties; and (c) study the evolution of these properties with each subsequent test. An MFHW, the Amungee NW-1H, completed in the Velkerri B shale in Australia, was analyzed. Due to a casing deformation and inability to mill out plugs beyond this, most of the flow contribution was from the heel stages of the well. The first F/BU period was conducted from 2016 to 2021 (a nearly 5-year buildup), while the second F/BU was initiated in 2021 (buildup is currently continuing). The extended (>1 month) production tests (EPTs) preceding the buildups were analyzed using rate-transient analysis (RTA) methods [flow-regime identification/straightline /type curve analysis (TCA)] modified for shale gas properties (e.g., desorption), while the buildups were analyzed using classic pressure-transient analysis (PTA) methods. The first (~5-year) buildup period (BU 1) revealed a sequence of bilinear-linear-elliptical-pseudoradial flow followed by a second linear flow period. The first two flow regimes are interpreted to be associated with interfracture flow, while the latter is assumed to correspond to linear flow to the well. Elliptical/radial flow around fractures is rationalized to occur due to interpreted relatively short fracture half-lengths (corresponding to the high-conductivity portion of the fractures). Permeability estimates are in good agreement with diagnostic fracture injection test (DFIT) analysis. Flow-regime interpretations for the other test periods (EPTs 1 and 2, BU 2) are largely consistent, although EPT 1 flow-regime interpretation was challenged by noisy data. Permeability values derived from EPTs 1 and 2 are smaller than from buildup tests, suggesting stress sensitivity caused by drawdown. Properties derived from the analysis of BU 1 and 2 are in good agreement, suggesting that any effects caused by stress sensitivity of reservoir parameters are largely reversible. Permeability derived from all tests are much larger than those obtained from laboratory data, leading to the interpretation that natural fractures are elevating system permeability. Fracture half-lengths are also much shorter than those typically reported for MFHWs. The mostly “textbook” quality well test data obtained for this field example, combined with the length of the test periods, resulted in one of the most complete flow-regime sequences observed for an MFHW completed in a shale gas reservoir. The existence of a radial flow period observed for all test periods (interpreted to be interfracture radial flow) allows for confident estimates of reservoir permeability/skin and their evolution with each subsequent test, which is rarely reported. The radial-flow-derived permeability, combined with early linear flow analysis, also allowed fracture half-length to be estimated for all tests. This case study adds significantly to our understanding of shale gas reservoir characteristics and flow-regime sequences associated with MFHWs.