Late Life Field Management with Instrumentation Failure. Modelling Predictions and Successful Validations of Late Life Subsea Gas Condensate System Using Historical Field Data

Depleting reservoir pressure, increasing water cut and decreasing overall system production leading to increased liquid holdup are among the key challenges for typical late life gas condensate production system. This paper elucidates modelling details of a late life offshore subsea gas condensate system and how the findings are implemented and validated with actual field data for successful outcomes. There is only one subsea well remain in operation with relatively long subsea flowlines. Subsea pressure and temperature transducers are out of service as the asset approaches the end of design life. In this context, flow assurance team has taken the modelling approach in order to minimize cost and to maximize values. Detailed transient multiphase thermohydraulics models are developed and benchmarked against field data. Historical field data over the past two years are utilized in order to predict the trend for key parameters such as well production rates and water to gas ratio (WGR). Matrix of simulation including the predictions of slugging flow regimes are carried out for the entire flow path, from reservoir characteristics descriptions at bottom hole, through flow regimes analysis at topsides slug catcher. Three categories of operation characteristics, namely the low risk, medium risk, and high risk production periods are identified. It is predicted that the system would start to fall into slugging flow regimes from 2 months onwards with final production end date of after 10 months. This is shared with wider team such that operations and base management teams are informed with predicted multiphase flow characteristics for the remaining production life. As such, gas supply succession plan can be executed in time to ensure uninterrupted downstream commercial agreement. Feedbacks from operations team revealed accurate predictions of such analysis, including slugging flow phenomenon which was associated with flow and pressure fluctuations, was observed in field as predicted by the study. More importantly, the production cut-off date is accurately predicted 10 months ahead and within the accuracy of ± 1 week. This study demonstrated how historical field data, coupled with detailed transient multiphase thermohydraulics modelling, can be utilized for offshore gas condensate production predictions during late life. Without transducers and/or virtual metering data feed, production end date can be accurately predicted based on key parameters analysis. This is particularly valuable for supply succession planning and is deemed a successful case study with significant positive outcomes which can be used as reference for other gas condensate assets.