The contribution investigates the relationship between in situ stress regimes, natural fracture systems and the propagation of induced hydraulic fractures in APLNG's (Australia Pacific Liquid Natural Gas) acreage within the Jurassic to Cretaceous Surat Basin in southeast Queensland. On a regional scale the data suggest that large basement fault systems have significant influence on the lateral and vertical interplay between geomechanical components which ultimately control permeability distribution in the area. At a local scale we show several case studies of significant in-situ stress variations (changes in tectonic regime from reverse to strike-slip, changes in horizontal stress orientation as well as changes in differential horizontal stress magnitude) which are identified from wireline image log interpretations and geomechanical models constructed from wireline sonic and density data. These variations are reflected in hydraulic fracture propagation, which is monitored through microseismic monitoring, tiltmeter monitoring. Reverse stress regimes result in the propagation of horizontal fractures; in areas of higher differential stress linear hydraulic fracture orientations are common, whereas in regions of lower differential stress the orientation of hydraulic fractures appears influenced by both stress and pre-existing fractures. The paper is relevant for fracture simulation in areas with complex in-situ stress regimes. The major technical contribution of the study is the use of geomechanical modelling for predicting hydraulic fracture propagation styles.

Modern hydraulic fracture treatments are specifically designed to unlock reserves from particular rock types, especially in unconventional reservoirs. Progressive improvements in fracture design can be critically informed by post stimulation pressure analysis, yet this process is often overlooked. This paper documents the evolution of fracture designs by successively incorporating post-stimulation pressure analyses after major design changes that ultimately led to the design-optimization of fracture treatments in low permeability coals. The coals under context are the Walloons coal measures in Jurassic to Cretaceous aged rocks in the Surat Basin of southeast Queensland, Australia.Significant challenges are faced in stimulating the Walloons coal measures due to their thinbedded nature, that range from 0.2 to 3.0 m [0.66 to 9.8 ft] in thickness and, which are also inter-bedded with low permeability siltstones, minor sandstones and carbonaceous shales. Net coal thickness is 20 to 40 m [98.43 to 131.23 ft] in a gross sequence of 300 to 400 m [948.3 to 1,312.3 f] thickness. Reservoir complexity is further impacted by lateral continuity variations of coals, which generally have a high Poisson's ratio (Ͼ0.32). In particular where coal reservoirs display low permeability, understanding and implementing reservoir beneficial fracture treatments becomes pivotal to successful well performance.Modification of fracture designs during the fracture campaign included changing key parameters such as fluid types, pump rates, proppant loading and gel concentration. Both, the treatment and the calculated bottom-hole pressures, were evaluated using 3D fracture models, supplemented by an array of diagnostics such as surface tilt-meters, diagnostic fracture injection tests, micro-seismic monitoring and tracer logs as well as log derived stress models. The results of these diagnostics helped shape the design changes implemented throughout the campaign and has influenced designs for future trials also. Ultimately, it was observed that the treatments that were pumped using low gel loadings in conjunction with high proppant concentrations, and at relatively lower rates, resulted in better well performance.This paper presents the design and treatment evaluation process and also provides an insight into the progression of fracture design and subsequent treatments which were successful in overcoming reservoir complexities. The outlined approach can be used to refine hydraulic fracture treatment designs in similar complex reservoirs in Queensland, with worldwide applicability.