Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

Abstract

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.

Basement structural architecture and hydrocarbon conduit potential of polygonal faults in the Cooper‐Eromanga Basin, Australia

“…After this event, the maximum horizontal stress orientation rotated to approximately N-S during the Paleogene to approximately E-W at present day (Müller et al 2012;Pokalai et al 2015aPokalai et al , 2015bPokalai et al , 2016. The present-day stress regime is oriented approximately 101°N under a strike-slip to compressional stress regime with a maximum horizontal stress magnitude of approximately 41.9 MPa at 1 km depth (Reynolds et al 2006;Nelson et al 2007;Pokalai et al 2016). The minimum horizontal and vertical stress magnitudes are approximately 18 and 21.5 MPa at 1 km depth, respectively, but can change locally between strike-slip and compressional stress regimes (Nelson et al 2007).…”

“…Eromanga Basin sediment deposition ceased with the onset of the Upper Cretaceous E-W crustal shortening event that formed a regional unconformity isolating the Eromanga Basin from the overlying Paleogene to Quaternary Lake Eyre Basin (Kuang 1985;Apak et al 1997;Gravestock and Jensen-Schmidt 1998;Mavromatidis 2006). After this event, the maximum horizontal stress orientation rotated to approximately N-S during the Paleogene to approximately E-W at present day (Müller et al 2012;Pokalai et al 2015aPokalai et al , 2015bPokalai et al , 2016. The present-day stress regime is oriented approximately 101°N under a strike-slip to compressional stress regime with a maximum horizontal stress magnitude of approximately 41.9 MPa at 1 km depth (Reynolds et al 2006;Nelson et al 2007;Pokalai et al 2016).…”

An automated cross‐validation method to assess seismic time‐to‐depth conversion accuracy: a case study on the Cooper and Eromanga basins, Australia

“…; Kulikowski, Cooke and Amrouch ; Pokalai et al . ; Kulikowski ; Kulikowski and Amrouch , ; Kulikowski et al . , ).…”

“…Subsequent structuring took place during six tectonic events, which developed fault sets and a complex distribution of conjugate natural fracture sets, while also reactivating pre-existing faults (e.g. Kuang 1985;Apak et al 1997;Kulikowski, Cooke and Amrouch 2016c;Pokalai et al 2016;Kulikowski 2017;Amrouch 2017, 2018a;Kulikowski et al 2016b. The large structural traps (anticlinal and fault bound traps) within Permian stratigraphy have been the target for gas production, namely within the gas saturated Patchawarra and Toolachee formations.…”

A Statistical Approach to Assessing Depth Conversion Uncertainty on a Regional Dataset: Cooper-Eromanga Basin, Australia

“…The Permian aged Cooper Basin is Australia's largest onshore hydrocarbon province, with the overlying Jurassic to Cretaceous aged Eromanga Basin consisting of low relief structural traps that contain the majority of the oil currently being explored for (Kulikowski et al, 2016a;Lowe-Young et al, 1997;Pokalai et al, 2016). To predict whether low relief structural traps exist within the province, geophysicists must select a depth conversion method that provides minimum error.…”