CNV field in offshore Vietnam is experiencing excessive surface back pressure due to extended production pipeline and increasing field gas-oil ratio (GOR), which not only constraints the production from existing wells but also creates a challenge in evaluating production gain from future development activities. Therefore, it is critical to properly account the back pressure effect to generate a reliable long term production forecast for further investment decision. This paper describes the details of integrating subsurface dynamic reservoir simulation model with surface network simulation model to holistically assess the impact of back pressure. The conventional method of using standalone dynamic simulation model is compared against the integrated model. The well control mode in the reservoir model is updated with the response of the network model, which consist of wells, topside piping, facility equipment and export pipelines. With this approach, the surface pressure constraints and responses will be captured, and the reservoir, well and network performance will be impacted accordingly. A unified field management is designed using an advanced orchestration engine to control the well operating conditions, schedule well activities and activation of equipment in the operational cycle. Thorough assessment can be performed with the inclusion of accounting interactions between reservoir and network parameters. This integrated modelling workflow allows multiple domains of reservoir engineering, production engineering and engineering contractors to collaborate and achieve a better understanding of the impact of surface back pressure by producing a representative forecast of production profile. To address the back pressure problem in the current facility, debottleneck the surface network and improve production was evaluated by installation of additional surface equipments such as booster pump and compressor. In general, the integrated model provides critical insights to the field development planning, evaluation for de-bottle necking surface system and production optimization. There is lack of publication on the successful usage of the integrated surface network with subsurface dynamic simulation as it is uncommon for this feature in conventional modelling workflows. This paper describes the successful case of the implementation of an integrated simulation modelling workflow to simulate long term surface back pressure effect, back pressure from additional production into the system, and benefits of new surface equipment installation. Highly efficient and accurate prediction tool was developed in the scope of this study.

TGT field is located offshore Vietnam, at a water depth of 45m and approximately 100km Southeast of Vung Tau. The field started production in 2011 and is currently producing about 13k bopd. The produced crude is 38-40 deg. API with viscosity of 0.45 cP at reservoir conditions and classified as light oil. The field consists of three wellhead platforms with nearly 40 production wells, all being gas lifted. Emulsion, which is rarely encountered in downhole environment and not reported in the surrounding oil fields, was diagnosed to be present in production tubing of TGT wells by two indications: measured bottom-hole flowing pressure (BHFP) remarkably higher than calculated value, and emulsion observed on surface well fluid samples. Upon completion of the laboratory testing for chemical selection, in early 2020 a field trial was carried out by injecting demulsifier into the production tubing of selected wells via the chemical injection line or together with lift gas. A successful field trial resulted in a clear reduction of BHFP of the wells along with a production increase by approximately 13% from 8 tested wells. Due to the low-cost of the application and major economic gain compared to other IOR methods, long-term downhole demulsifier injection has been applied in additional wells for increasing the field production. Unlike for heavy oil developments, there is a lack of publications on downhole emulsion and demulsification for light oil fields. This paper describes a case study for application in a light oil field, covering identification of the wells having an emulsion issue in the production tubing, laboratory testing for selecting demulsifier, challenges in chemical deployment and the field trial results.