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.

Walloons Coals of the Surat Basin, Queensland (Australia) contain world class Coal Seam Gas (CSG) plays, where permeability varies from high (>1Darcy), due to Gaussian curvature-related natural fracture connectivity, to low (<1mD) due to unidirectional fracture-systems attributed to regional unidirectional flexure. The low permeability Walloons Coals require stimulation to unlock their gas resources. This contribution describes the design evolution of stimulation concepts in the Surat Basin in context of five key subsurface drivers Coal net to gross: Surat Basin coals contain 30 coal seams with a cumulative thickness of 20-35m in a gross rock column of >300m Permeability of coals requiring stimulation for economic flow rates varies from <1mD - ~30mD Varying stress regimes, both vertically and laterally Ductile rock properties in Walloons coal reservoirs Productivity Index drop (PI drop) can occur when (incompressible) water is replaced by (compressible) gas during coal dewatering Early stimulation treatments in Surat Basin (pre-2010) followed ‘standard’ high rate water/sand designs adapted from the shale industry. However, high treating pressure and rates resulted in several instances of casing shear (Johnson et al. 2003) particularly at depths associated with stress regime transitions. Subsequent designs (2010-12) repeated water fracs albeit including ample diagnostics (Johnson et al 2010; Flottmann et al 2013), showing that water fracs appear to be ineffective in stimulating Walloons Coals. Design optimizations in 2015 (Kirk-Burnnand et al. 2015) based on extensive modeling work (Pandey and Flottmann 2015), identified low rate gel fracs as optimal to stimulate rocks with ‘ductile’ Walloons-specific coal properties. However, treatment rates were limited to optimize height growth, both to connect coals and to avoid height growth into non-reservoir. Initial production data indicated a drop in well productivity in some fracture stimulated coals (Busetti et al. 2017). Consequently, stimulation designs were modified in late 2016 to account for such productivity drops while maximizing the fluid recovery. Early time post stimulation drawdown strategy was also field-tested to mitigate loss of well productivity due to excessive drawdown which could cause partial or full fracture closure (especially near the wellbore region), and lead to loss of communication between reservoir and well. Sub-surface drivers identified in tight Walloons Coals control the effectiveness of any stimulation option deployed. These drivers influence the effectiveness of stimulation in multiple ways. First, these drivers can lead to a sub-optimal connectivity between well and reservoir resulting in poor productivity and marginal recovery. Second, the drivers may influence an operator towards expensive stimulation options which may provide better well to reservoir connectivity but diminish the economic value due to the high costs involved. Hence the inclusion of sub-surface drivers in selecting stimulation design is paramount as demonstrated in this paper.

One of the keys to successful and environmentally responsible well stimulation programs in coal seam gas development is to establish consistent procedures for the safeguarding, planning and executing activities across multiple wells. The aim of this paper is to show how a novel application of petrophysical program scripting can be used to make the stimulation process more efficient, consistent and compliant across assets with varying requirements. A macro embedded in petrophysical evaluation software applies a series of rules to rank coals by thickness, allocate a series of perforations and stimulation type based upon coal rank and spacing and then produces actionable treatment schedules which are seamlessly implemented in well stimulation operations at well sites. To do this, the macro grades all coals within the well by thickness based upon a cut-off on the density log, with the thickest coal being graded highest. The macro then identifies the top ranked coal and places perforations based on user defined logic, geological information from offset wells, permeability attributes of the target coal layer(s), depth and vertical separation between adjoining coal targets. Based on the stimulation type assigned, a stimulation schedule is generated that includes estimates of fluid volumes, proppant volumes, injection rates, proppant ramp type and stipulates flush conditions (over-flush or under-flush). Coals thicker than a maximum perforation size are perforated in an upper, middle and lower configuration. Most coals are thinner than the maximum allowable perforation interval and so the macro looks up and down the borehole to include thinner coals within a potential perforation window. The system then generates the stimulation schedule as described above. The macro continues to allocate perforations and stimulation schedules for each validated coal interval and sequentially tries to maximise the total target coal interval along the wellbore. Certain environmental constraints are included in the macro logic to maintain local and regional commitments. For example, coal zones in proximity of permeable non-coal layers i.e. interburden are automatically excluded from stimulation. Multiple advantages of this system have been realised including, a) effective QA/QC as outputs can be directly plotted against the well logs giving the user a quick and easy visual check b) actionable instructions that site based teams can execute including exact perforation depths and stimulation schedules c) provide realistic materials and costs estimates that ensure efficient planning and logistics, d) monitor and document any variations between allocated schedule versus actual execution, e) provide estimate of expected net coal connectivity at a well, development package and asset level which feeds into production and recovery forecasts, f) plan future optimisation studies or pilots and g) most importantly offers a consistent, efficient and compliant framework that can be applied across multiple assets, engineering teams and service providers. This paper focuses on capabilities and advantages of using a macro to automate stimulation design allocation for CSG multi-well (>100 wells) assets. Details of individual stimulation designs for Walloons Coal measures are mentioned in other publications (Kirk-Burnnand et al., 2015 and Flottmann et al. 2018) and hence not covered here.