The paper discusses on reservoir souring study in a deep water subsea green field as a result of seawater injection. The objectives are to determine likelihood, timing of reservoir souring to happen and amount of expected produced H2S. Offshore deep water development involves considerable CAPEX investment hence reservoir souring requires to be assessed in order to make techno-commercial judgement involving formulating the field development plan, upfront identification of prevention & mitigation strategy, operating strategy and project economics. The study started by performing data gathering involving among others field information, PVT, mineralogy, water analysis data, and production and injection profile. Subsequently, 2D reservoir modelling and 3D reservoir modelling was built. Sensitivities cases were run by varying the injection rate, nutrient loading, rock abstraction capacity, sulphate content, injection temperature and bacteria growth time. This is followed by sensitivity analyses for mitigation options using biocide injection, nitrate injection, H2S scavenging and sulphate removal in the field. Based on the results obtained, prevention and mitigation strategy has been evaluated and ranked followed by comparison with nearby analogue fields. The modelling results of all scenarios indicate that reservoir souring will happen in the field and beyond HSE safety limit. For some scenarios, the H2S partial pressure exceeds NACE limit before end of field life, hence requiring team to re-evaluate material selection options. Water injection rate and rock abstraction capacity have the largest impact to the H2S breakthrough time. Sensitivity analyses for mitigation options have been conducted based on consideration of having options of biocide injection, nitrate injection, H2S scavenging and sulphate removal in the field. Biocide injection does not have considerable effects on H2S level. Nitrate injection only partially reduces H2S generation mainly due to high nutrient content in the reservoir and high sulphate content in the injected seawater. On the other hand, sulphate removal analyses indicate its effectiveness in preventing reservoir from becoming sour. The outcome of the study is then incorporated in the field development plan and operating strategy. The paper highlighted comprehensive step by step approach to understand reservoir souring potential in a deep water development via 2D and 3D modelling approach. This can be included as an important procedure in field development especially involving high CAPEX development whereby critical decision making need to be made upfront. In addition, benchmarking, and learnings from nearby deep water fields help to identify best preventive and remedial option for reservoir souring.

L-B is a clustered deepwater development comprising two greenfields currently approaching execution stage. The development concept is subsea umbilical, risers and flowlines (SURF) with dedicated Floating Production Storage and Offloading (FPSO) in L field and a long subsea tieback (20km) for B field. Due to this, production assurance is a major risk particularly for B field during production. To enable a holistic simulation of the production and injection system, an integrated network model (INM) is developed. This paper presents the systematic and integrated approach in developing the INM for L-B cluster, the calibration processes, and the resulting field modifications undertaken as an outcome of the model. The INM comprises dynamic reservoir model, well model and network model coupled using an integrator software. Robustness of each standalone model were assured through stringent construction and reviews by respective disciplines. Multiple collaborative forums participated by cross-function members were held to integrate the models. Next, a custom algorithm and method were developed to address specific field controls such as staggered voidage replacement ratio and skin growth over time. Once the models were compatible, multiple scenarios identified from Concept Identification Workshop were evaluated with INM. The results were then integrated into fiscal evaluations and ultimately facilitated decision-making for L-B project. Thorough utilization of the completed INM models generated vital data for future cluster production forecast of L and B fields: The in-situ FPSO operating pressure was accurately simulated using INM resulting in a dynamically responsive production profile, instead of sole dependence on reservoir model which uses a static pressure set up. INM was also used to identify and mitigate potential bottleneck along production system. Preliminary artificial lift options of Electrical Submersible Pump (ESP), Downhole Gaslift (DHG), Subsea Multiphase Pump (MPP) and Riser based Gaslift (RBGL) were analyzed and selectively narrowed down using INM. Outcomes of the analysis were favorable to MPP and RBGL which were then incorporated in the Concept Select scenarios. Ten scenarios with permutations on recovery method, onset of pressure booster installation, and artificial lift requirement were analyzed and decisively selected using results from INM. Study of new technology such as subsea separator was also concluded to be inapplicable in the field via INM evaluation. Finalized temperature modeling was used to cater for flow assurance constraints such as minimum Flowing Tubing Head Temperature (FTHT) requirement and generated inflow information to be incorporated into specialized Flow Assurance (FA) software. This paper will highlight the benefits of a comprehensive integrated network model covering end-to-end operations to mitigate flow assurance risk prior to field start-up. This model will also be readily utilized during the crucial production stage for calibration with actual field data to generate reliable prediction. The long-term application of INM will give greater assurance of production attainability in the L-B clustered development.