Geomechanical Risk Assessment of Injection Test for a CCS Site Appraisal, Offshore Northern Territory

Abstract

Abstract In the context of Carbon Capture and Storage (CCS) site appraisal procedures, the assessment of geomechanical risks associated with injection tests is important. Assessments can calculate injection pressure thresholds and guard against formation fracturing and solids production during fall-off tests or due to unplanned shut-in occurrences. The Bonaparte CCS project (West Peron), situated northeast of the Petrel Field, offshore Northern Territory, serves as a pertinent case. Two vertical appraisal wells are included in the appraisal work scope, complemented by an extensive data acquisition program. The primary scope of appraisal drilling is to fully characterise the storage site, focusing on confirming the storage reservoir and cap rock continuity and properties along with the assessment of matrix injectivity within the storage reservoir. A geomechanical study has been conducted to assess the risk of formation fracturing and sanding during a water injection test. Existing well data and supplementary core testing data from the nearby Petrel Field have been used to develop a comprehensive 1D geomechanical model for the storage reservoir and cap rock formations in the area under assessment for CCS feasibility. Considering the temperature difference between the storage formation and the injection fluid, the cooling effects could lead to a reduction of almost 15% in fracture initiation pressure (FIP). Notably, the FIP for perforations aligned parallel to the azimuth of the maximum horizontal stress is lower than for those aligned parallel to the azimuth of the minimum horizontal stress. This configuration signifies that while injection pressures surpassing FIP might trigger tensile fracturing in specific perforations, fracture propagation from the wellbore remains unlikely if the injection pressure remains below the minimum horizontal stress. The pressure requirements for current envisaged matrix injection rates fall below the estimated FIPs. Consequently, the risk of formation fracturing during the injection test is deemed low. The propensity of sanding during flowback, considering a range of rock weakening and thermal effects of water injection, is also found to be low.