--> Steam Temperature Monitoring

AAPG Middle East Region GTW, Maximizing Asset Value: Integrating Geoscience with Reservoir Management & Facilities Optimization

Datapages, Inc.Print this page

Steam Temperature Monitoring


The “Q” field is a highly fractured carbonate reservoir located in central Oman at a depth of approximately 350m with a maximum oil column thickness of 170m. The reservoir contains approximately 1bln bbls in-place of 16API oil with an average viscosity of 220cP, making conventional Gas-Oil-Gravity Drainage unsuitable due to low gravity drainage rates to the oil rim. After obtaining encouraging pilot results, a full-field Thermally Assisted GOGD (TAGOGD) concept was adopted in order to lower the oil viscosity in the matrix through heating by steam injection into the fractures. The TAGOGD project is the first of its kind in the world. The project was sanctioned in 2007 and first steam injection was in 2011. Daily monitoring of well, reservoir and facility performance is critical to the project’s success. The complexity of the process warrants the use of extensive field monitoring systems, including numerous DTS installations in both vertical observation and horizontal production wells, real-time reservoir pressure measurements, real-time microseismic processing and imaging, micro-gravity, and inSAR / optical leveling for surface deformation monitoring. The collection and analysis of a wide variety of data-sets results in a constantly evolving understanding of the reservoir’s response to steam injection. Of critical importance is the understanding of the fracture system and its ability to transport and accommodate steam. Recent analysis of field temperature data and comparison to expectations derived from the performance of the steam injection pilot has resulted in efforts to re-calibrate the dynamic models and make adjustments to the anticipated field performance. Temperature management of produced fluids is a critical component of the steam project. Condensed steam is continuously produced by the gas-lifted horizontal producer wells, and overtime the produced fluid temperatures are expected to rise. Worst-case simulations conducted for the FDP indicated that the onset of elevated produced fluid temperatures would not be significant for up to 10 years after first steam. This perception justified delaying construction of the wet oil & gas coolers and made a case for the installation of low-temperature rated GRE flowlines transporting fluids from the well to the plant. Despite field steam injection rates being more than 50% below FDP targets, 5 out of 19 wells have approached the temperature limitations of the GRE flowlines within 5 years of first steam. A variety of surface projects are in different stages of development with a common goal to develop long-term solutions to managing the early onset of elevated temperatures. Various WRFM activities have also been implemented, most providing short-term solutions to issues that are expected to grow quickly in severity. Execution of these projects alongside various other recovery projects is expected to enhance production robustness, thereby allowing for the full realization of the field’s maximum production potential through steam injection.