--> Geomechanical Insights In The Bedout Basin: Exploiting Technologies For Understanding Reservoir Settings (Title Changed 10May)

AAPG Asia Pacific Region GTW, Pore Pressure & Geomechanics: From Exploration to Abandonment

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Geomechanical Insights In The Bedout Basin: Exploiting Technologies For Understanding Reservoir Settings (Title Changed 10May)

Abstract

Quadrant Energy (former Apache Australia) has drilled several exploration/appraisal wells in the Bedout Basin to characterise multiple reservoir targets in different structures. Early in the drilling campaign, excessive dynamic losses provided evidence that subsurface fluid flow during potential exploitation operations could be influenced by faults and natural fracture systems. Because the permeability framework in some of these faults and natural fracture systems are likely controlled or influenced by earth stresses, a comprehensive drilling data acquisition program was designed to collect LWD image data, wireline image data, whole core and sidewall core plugs. Interpreting the image data provided important information to document time-dependent changes in borehole conditions between initial drilling and several days later. Whole core from Roc-2 provided an opportunity to perform a series of single-stage tri-axial compressive strength tests to calibrate an empirical tool for estimating rock strength (UCS) in other wells in the Bedout Basin. This new information was used to better interpret the LWD and wireline image data.

Drilling-induced tensile cracking was pervasive in the Phoenix South-1/ST2, Phoenix South-2, Roc-1, and Roc-2 wells. The SHmax directions inferred from tensile cracking indicated a near east-west compression over the greater Bedout Basin area. In many cases, tensile cracking was not confined to a single axial crack, but occurred across a portion of the borehole wall that was up to 20 degrees wide. In some sections, rather than creating a new axial crack in these near-vertical wells, the tensile region of the borehole propped open natural fractures in the tensile region (e.g., drilling-enhanced natural fractures).

Forward modeling SHmax stress magnitudes requires reliable estimates of the least principal stress (S3). The available leak-off test data from regional offset wells was highly variable and potentially problematic for fine-scale stress modeling. To investigate this variability, an extended leak-off-test (XLOT) was performed at the 9 5/8” casing shoe in Roc-2 to create a crack for sampling the far-field S3. Pressure results indicated a S3 or Shmin ~1.83 SG at the shoe where subsequent image data showed that a clear hydraulic fracture had formed. A similar XLOT was performed in Phoenix South-2 and the initial interpretation was that Shmin was ~1.56 SG. Analysis of the image data near the shoe depth in Phoenix South-2 indicated that pressurised drilling fluids likely re-initiated slip along a natural fracture resulting in an operational fracture gradient that we now refer to as the natural fracture gradient (NFG).

Modeling image-based wellbore failure in the Bedout Basin wells converged on a stress state that is pure strike-slip with sufficient magnitudes to support active faulting along steeply-dipping optimally-oriented faults and fracture systems. Based on this stress state in Roc-2 and Phoenix South-2, the occurrence of isotropic wellbore breakouts only occurred where UCS ~50 MPa or less. Interestingly, there were sections in these exploration wells where advanced modeling indicated anisotropic breakout development in sections where the UCS is considerably greater at 60-100 MPa and internal friction is high (> 1.5) due to interaction of the wellbore with weak natural fractures or joints that tended to trend slightly oblique to the east-west SHmax stress direction.

A significant pore pressure well control event occurred in the Phoenix South-2 well that resulted in abandoning the well. Wellhead pressures during this well control event inferred a pore pressure regime that could be as high as 1.56 SG or greater. The pre-drill log-based pore pressure prediction (seismic-based was deemed unreliable) for Phoenix South-2 did not find any evidence that could explain the pressure kick nor could the data support a systematic pore pressure ramp culminating to the pressure kick. A third-party pore pressure postmortem review of the same data interpreted an onset of a pore pressure ramp several hundred metres shallower near the shoe and reaching a peak consistent with the observed kick. To address this pre-drill and postmortem contradiction, we used our knowledge of the stress state and rock strength, coupled with LWD and drilling mechanics data to calculate wellbore breakout development based on the equivalent static density (ESD) of the mud. We found that under-balanced conditions would be progressively more pronounced with depth based on the third-party elevated pore pressure ramp. If this was the case, we would have expected excessive wellbore breakout development resulting in an increase in cavings, possible tight-hole, high torque, or overpull drilling events. However, the hole section down to the kick location in Phoenix South-2 indicated a near perfect in-gauge hole with no adverse drilling problems or cavings whatsoever.