Comprehensive Geomechanical Modeling and Wellbore Stability Analysis for Infill Drilling of High-Angled Wells in a Mature Oil Field

Abstract

Reservoir pressure depletion and decline of production are two common features of many mature petroleum fields. Drilling and stimulation of long, highly-deviated wellbores is one of the many technologies commonly used to enhance the production in mature fields. Reservoir depletion results in reduction of in situ horizontal stresses and more specifically in the formation fracture gradient (FG). The presence of non-depleted and generally weak interbeds within the pressure depleted reservoirs with a low FG leads to a narrow drilling margin for new infill wells or laterals. Therefore, a robust knowledge of rock mechanical properties, formation pressures, the magnitude of in situ stresses and their evolution with production and depletion are essential for successful drilling of new wells in particular and the redevelopment of mature fields as a whole. A case study from a mature oil field in the Sarawak Basin, offshore Malaysia, is presented where the field geomechanical elements were constrained from field data acquired in more than 10 offset wells drilled in early 1980s, and a new re-development well drilled in 2014 with supplementary core, well logs and pressure data. The results of rock mechanical core tests along with acoustic logs in the new well were used to update and verify an early geomechanical model built in the area. Extensive production from more than 20 multi-layer sandstone reservoirs resulted in significant pressure depletion whilst some of the deeper and stronger reservoirs still contain significant oil reserves. The geomechanical model was used to identify the narrow-margin drilling and stability risks of infill deviated oil producers targeting by-passed oil in the deeper reservoirs, and horizontal water injectors planned to enhance oil recovery in the field. The results showed that both intermediate and production sections of planned wells would have narrow mud weight windows. Depending on the well trajectory, the production sections could have only 0.8 ppg drilling margin due to a higher depletion of deeper reservoirs. The analyses also highlighted thin, weak interbeds in the intermediate hole section that require a minimum mud weight of 10.0-10.5 ppg to limit shear failure to a manageable level considering hole cleaning challenges in high-angled wells whilst the FG of depleted sections could be as low as 11.3 ppg requiring stringent control on downhole pressure while drilling to keep the hole pressure within the safe margin. Optimum mud weights, safe drilling margins and casing setting points were determined for nine different well trajectories focusing on the azimuthal and inclination dependency of fracture and borehole collapse pressures. The subsequent drilling campaign of planned infill oil producers and water injectors in the field has been successful due to good drilling practices, using the recommended mud programs consistent with wellbore stability assessments, and careful bottomhole pressure control.

Integration of geological and well log and geomechanical modeling toward a safe mud weight for wellbore stability: A case study of Ruby field, Blocks 01&02, Cuu Long basin

“…In this paper, the authors will use wireline logging data including gamma ray, density log, resistivity log, sonic log, in conjunction with drill stem tests (DSTs), LOT, MDT, drilling events, and production data from the Ruby field, Blocks 01&02, Cuu Long basin. This comprehensive dataset will be used to construct the 1D geomechanical model (1D MEM), providing parameters such as the pore pressure, formation stresses and mud weight windows [6]. Afterward, this model continues to be updated and refined with the future wells to ensure the minimization of drilling…”