Fully-Coupled Wellbore Design and Optimization for Thermal Operations

Abstract Steam Assisted Gravity Drainage (SAGD) is a widely used enhanced oil recovery process applied in Canadian oil sands projects. Operators of SAGD projects have long been aware that many factors such as near wellbore geology, tubular sizes, lengths, and the allocation of fluid rates between tubulars in multi-string completions, can significantly impact the effectiveness of well and well- pair operations. The interaction of well components within these complex wells and the reservoir can impact the economic and technical success of the entire project either positively or negatively, suggesting that a means of optimizing this interaction that couples wellbore effects with the reservoir is required. Simulation studies were carried out to investigate the impact of wellbore design optimization on the well's performance. Reservoir simulation was used as a tool to evaluate the advantages derived from the optimization of wellbore and tubular design for thermal projects using a new fully coupled reservoir-wellbore modeling approach linked to an optimization algorithm. This paper presents results that cover important aspects such as the impact of geological heterogeneity on wellbore design; the optimization of length and positioning of multiple tubular strings within a liner for both injection and production wells; and the optimization of the allocation of injected steam between multiple tubing strings. The results indicate positioning of tubulars in a multiple tubing completion SAGD well pair have a significant impact on the steam chamber growth, productivity, SOR and ultimately on NPV. This paper presents results of two optimization cases. The base case wellbore completion had two tubing strings, the short tubing string was landed at the heel while the long tubing string was landed at the toe of the horizontal SAGD well pair. First optimization was performed by changing the length/placement of tubing strings in the injector and the producer. Optimization of tubing placement increased the NPV of the well pair from 16.3 M$ to 20.7 M$ over 8 years. The Second optimization study was performed including the tubing placement similar to the previous case along with the SAGD operating strategy in terms of steam injection rate that was allowed to change every two years. In this case the NPV was optimized from 16.3 M$ to 25.79 M$ over 8 yrs.