Emma J. Nelson

PRESENT-DAY STATE-OF-STRESS OF SOUTHEAST AUSTRALIA

There have been several studies, both published and unpublished, of the present-day state-of-stress of southeast Australia that address a variety of geomechanical issues related to the petroleum industry. This paper combines present-day stress data from those studies with new data to provide an overview of the present-day state-of-stress from the Otway Basin to the Gippsland Basin. This overview provides valuable baseline data for further geomechanical studies in southeast Australia and helps explain the regional controls on the state-of-stress in the area. Analysis of existing and new data from petroleum wells reveals broadly northwest–southeast oriented, maximum horizontal stress with an anticlockwise rotation of about 15° from the Otway Basin to the Gippsland Basin. A general increase in minimum horizontal stress magnitude from the Otway Basin towards the Gippsland Basin is also observed. The present-day state-of-stress has been interpreted as strike-slip in the South Australian (SA) Otway Basin, strike-slip trending towards reverse in the Victorian Otway Basin and borderline strike-slip/reverse in the Gippsland Basin. The present-day stress states and the orientation of the maximum horizontal stress are consistent with previously published earthquake focal mechanism solutions and the neotectonic record for the region. The consistency between measured present-day stress in the basement (from focal mechanism solutions) and the sedimentary basin cover (from petroleum well data) suggests a dominantly tectonic far-field control on the present-day stress distribution of southeast Australia. The rotation of the maximum horizontal stress and the increase in magnitude of the minimum horizontal stress from west to east across southeast Australia may be due to the relative proximity of the New Zealand segment of the plate boundary.

In situ stresses of the West Tuna area, Gippsland Basin

The in situ stress tensor has been evaluated in the West Tuna area of the Gippsland Basin based on petroleum well data. Borehole breakouts and drilling-induced tensile fractures interpreted on image logs from six wells constrain the maximum horizontal stress orientation to ∼138°N. Four leak-off pressures and one closure pressure suggest the upper bound to the minimum horizontal stress in the West Tuna area is ∼20 MPa/km. The vertical stress was derived from checkshot velocity, density and sonic log data and the average value from sea-level is 20 MPa/km to 1km and 22 MPa/km to 3km depth. Formation test pressures indicate that pore pressure in the West Tuna area is hydrostatic above 2800 m. The maximum horizontal stress magnitude was constrained to 39 – 42 MPa/km based on the occurrence of drilling-induced tensile fractures on the West Tuna image logs. The in situ stress regime in the West Tuna area is therefore interpreted to lie on the boundary of strike-slip and reverse faulting (SHmax > Sv ≈ Shmin). The maximum horizontal stress orientation determined herein is broadly consistent with previous orientations derived from 4-arm caliper logs from nine other fields across the Gippsland Basin. The consistent northeast – southwest orientation suggests that large-scale tectonic forces are the primary control on the in situ stress tensor in the Gippsland Basin and indeed elsewhere in southeastern Australia. The horizontal stress magnitude in the Gippsland Basin with the minimum horizontal stress approximately equal to the vertical stress, are significantly higher than in other Australian basins including the Otway Basin. The (oblique compressional) plate boundary at New Zealand may be primarily responsible for the horizontal stress orientation and high horizontal stress magnitude in the Gippsland Basin and is discussed herein.

Fault reactivation potential during CO2 injection in the Gippsland Basin, Australia

The risk of fault reactivation in the Gippsland Basin was calculated using the FAST (Fault Analysis Seal Technology) technique, which determines fault reactivation risk by estimating the increase in pore pressure required to cause reactivation within the present-day stress field. The stress regime in the Gippsland Basin is on the boundary between strike-slip and reverse faulting: maximum horizontal stress (~ 40.5 MPa/km) > vertical stress (21 MPa/km) ~ minimum horizontal stress (20 MPa/km). Pore pressure is hydrostatic above the Campanian Volcanics of the Golden Beach Subgroup. The NW-SE maximum horizontal stress orientation (139°N) determined herein is broadly consistent with previous estimates, and verifies a NW-SE maximum horizontal stress orientation in the Gippsland Basin. Fault reactivation risk in the Gippsland Basin was calculated using two fault strength scenarios; cohesionless faults (C = 0; μ = 0.65) and healed faults (C = 5.4; μ = 0.78). The orientations of faults with relatively high and relatively low reactivation potential are almost identical for healed and cohesionless fault strength scenarios. High-angle faults striking NE-SW are unlikely to reactivate in the current stress regime. High-angle faults oriented SSE-NNW and ENE-WSW have the highest fault reactivation risk. Additionally, low-angle faults (thrust faults) striking NE-SW have a relatively high risk of reactivation. The highest reactivation risk for optimally oriented faults corresponds to an estimated pore pressure increase (Delta- P) of 3.8 MPa (~548 psi) for cohesionless faults and 15.6 MPa (~2262 psi) for healed faults. The absolute values of pore pressure increase obtained from fault reactivation analysis presented in this paper are subject to large errors because of uncertainties in the geomechanical model (in situ stress and rock strength data). In particular, the maximum horizontal stress magnitude and fault strength data are poorly constrained. Therefore, fault reactivation analysis cannot be used to directly measure the maximum allowable pore pressure increase within a reservoir. We argue that fault reactivation analysis of this type can only be used for assessing the relative risk of fault reactivation and not to determine the maximum allowable pore pressure increase a fault can withstand prior to reactivation.

Stress partitioning and wellbore failure in the West Tuna Area, Gippsland Basin

Image logs from the deep intra-Latrobe and Golden Beach Subgroups of the West Tuna area in the Gippsland Basin reveal that wellbore failure is restricted to fast, cemented sandstone units and does not occur in interbedded shales. Triaxial testing and analysis of empirically derived, wireline-log based strength equations reveals uniaxial compressive strengths of 60 MPa in sandstones and 30 MPa in shales in the West Tuna area. Conventional analysis of wellbore failure assumes constant stresses in the shales and adjacent sandstones and that breakout is focused in the weaker units. We propose that the flat lying, strong, cemented sandstone units in the West Tuna area act as a stress-bearing framework within the present-day stress regime that is characterised by very high horizontal stresses (SHmax > Shmin = Sv). Stress focusing in strong sandstone units can result in high stress concentrations at the wellbore wall and account for the restriction of wellbore failure to the strong sandstone units. Finite element methods were used to investigate the stress distribution in horizontal, interbedded ‘strong’ sands and ‘weak’ shales subject to a high present-day stress state such as exists in the West Tuna area (SHmax > Sv ~ Shmirl). Modelling using the present-day stress tensor and estimated elastic properties for the sandstones and shales indicates that the present-day stress is ‘partitioned’ between ‘strong’ inter-bedded sandstones and ‘weaker’ shales, with high stress being focussed into the strong sandstones. The stress focusing causes borehole breakout in the sands despite their higher strength. Conversely, stresses are too low to generate wellbore failure in the weaker shales.

In situ stresses in the North Sea and their applications: petroleum geomechanics from exploration to development

Present-day maximum horizontal stress (σ H ) is oriented northwest–southeast onshore North West Europe, reflecting the first-order control on intraplate stresses exerted by plate boundary forces. Stresses associated with deglaciation appear to influence the stress regime in the Northern North Sea, with σ H oriented E–W and a contemporary stress regime close to the transition between strike-slip and reverse faulting, i.e. σ H > σ v ~ σ h (where σ v and σ h are vertical and minimum horizontal stress respectively). Maximum horizontal stress orientations are highly variable in the Central North Sea and the stress regime within the sedimentary sequence appears to be detached from that in the basement. The stress regime in the sedimentary sequence of the Central North Sea is predominantly one of normal faulting with almost isotropic horizontal stresses (σ v > σ H ~ σ h ). Geomechanical risking of the likelihood of seal breach due to fracturing should incorporate the risk of reactivating sealing faults or fracturing intact cap seal rocks in shear or in tension. The risk of fracture-related seal breach is considered for stress regimes representative of the Northern and Central North Seas. Generally, reactivation of optimally oriented faults and/or shear fracturing of intact cap rock are the most likely mechanisms of fracture-related seal breach. However, in the Central North Sea overpressured scenario, tensile failure is the most likely mechanism of fracture-related seal breach. In situ stress data have value throughout the life cycle of a field. The implications of the stress regimes representative of the Northern and Central North Seas for naturally fractured reservoirs, wellbore stability, water flooding and fracture stimulation are analysed. These issues are stress-sensitive and the conclusions with respect to each issue differ significantly between the Northern and the Central North Sea because of their differing stress regimes.

Using geological information to optimize fracture stimulation practices in the Cooper Basin, Australia

Fracture stimulation treatments of tight formations in the Cooper Basin can be associated with hydraulic fracture complexity that results in abnormally high treating pressures, low proppant placement and poor economic success. Pre-completion (image log and rock testing data) and post-completion data (fracture stimulation pressure decline plots) were reviewed in 13 treatment zones from the Cooper Basin. Rock strength, image log and stimulation data were available for seven of those zones. From this analysis, a distinct relationship between rock properties (shear and tensile rock strength), geological weaknesses (natural fractures and other fabrics) and fracture stimulation complexity (net pressure, near-wellbore pressure loss and pressure-dependent leak-off) was observed. It is proposed that high in situ stress (Shmin≧0.8 psi ft−1; 18.1 MPa km−1), a large contrast in tensile strength between intact rock (T>1015 psi (7 MPa)) and pre-existing weaknesses in the reservoir (T∼0) promote the propagation of fracturing fluid along multiple fracture pathways, and thus abnormally high treating pressures, low proppant placement and poor economic success during fracture stimulation treatments in the Cooper Basin. The methodology used to predict in situ stress and hydraulic fracture complexity herein presents a potential generic approach that can be used in similar basins where hydraulic fracture complexity is a problem or where conventional stimulation practices are unsuccessful.