A Simulation coupling method for surface production system optimization is developed as part of an integrated operations (IO) project that aims to support the field rejuvenation program for a mature field. The objective is to unlock surface constraints and optimize field production via a production network-to-process facility coupling method. This method allows cross-discipline engineers to collaborate and perform comprehensive well deliverability assessment, evaluate network back-pressure and various facility constraints. Such collaboration also promotes the efficiency of optimization process. The well-pipeline production network and surface facility simulation models are coupled within a single application in which the hydraulic and thermal streams are tied for modeling consistency. These are configured at the upstream end of the separator system where common boundaries are solved sequentially. A "loop-back" approach is applied to impose facility constraints to the network and the well performance will be assessed based on its response to the system back-pressure and constraints. The coupled model is optimized by a neural-network solver where constraints are set up based on operation requirement such as flaring limit, process limits, gas lift requirement, erosional velocity limit, etc. Thorough analysis can be performed by incorporating and understanding the interactions between parameters and variables of the production system starting from the well, and progressing to the pipeline network, and to the processing facility. This allows personnel from multiple domains to collaborate and achieve the following: Restrategizing the separator pressure system to meet the production target while embarking on the vision of operating with zero gas flaring. The sensitivities of production network potential against surface capacity can be performed to identify the potential optimized operating setpoints.Reducing production deferment during prolonged operation equipment upset (i.e., when pump, compressor, or separator are shut down for maintenance). The deferment can be minimized by re-routing of production and/or re-allocating the gas lift distribution based on availability.Anticipating potential operational interruptions if operating setpoints of the production network and/or facility system are changed. These changes can be due to operational requirement or production enhancement initiatives. The coupling method provides critical insights to uncover opportunities of optimizing field production and minimizing production upset and interruption. The integrated operation improves the optimization process by promoting the collaboration of multiple domains. The outcome of the coupling method should be used as basis for further transient analysis check prior to field implementation, which is an additional key facet to its technical viability in terms of operational safety and avoidance to potential risk of production interruption.
Formation sand production is a major concern in brown field operations, especially as the field depletes and water production commences. There are many methods to control sand production in primary well completion; however, it becomes more challenging in producers where no primary sand control is installed initially, and it starts producing sand later in the well life. Selecting the right method for remediating these wells has become a hot topic with both Operators and Service Providers alike striving to discover effective and economical solutions for their brown-field operations. Currently, the solutions for through-tubing sand control in existing producers are screen hang-offs, through-tubing gravel packing1 (TTGP) and chemical sand consolidation. Through-tubing sand screen (TTSS) hang-offs above the producing zone, is an inexpensive sand control method. Unfortunately, these installations are typically short lived, often requiring regular well interventions due to screen plugging or erosion, or sand clean-out operations to remove sand accumulated in the production tubing. Alternatively, TTGP is a robust method to control sand production; however, more equipment is required to deploy the gravel pack which subsequently increases costs significantly in offshore applications. To simplify TTGP and make it economical, a major Interventions Service Provider devised a methodology to install TTGPs utilizing Slickine that reduces the overall installation cost tremendously. The methodology has been proven a great success in the US Gulf of Mexico where over 1,200 applications have been installed. The pilot implementation of slickline deployed through-tubing gravel pack (SL-TTGP) was executed in three S-Field wells in late 2018 which were shut-in due to higher than permissible sand production. These were challenging intervals in that they were uphole recompletions between cement packers in dual string 9-5/8" casing which had produced sand. The results from the installation proved that the methodology provides effective sand control and enables reinstatement of production from these wells. Further, the installations were achieved with lesser resources and at lower costs; less than half that of a CTU deployed TTGP. This success has led to further installations in the following year. This paper presents in detail the case study of the pilot implementation of SL-TTGP, key successes, as well as critical lessons learnt during execution and production phase. It includes the challenges, risks and their recommended mitigation plans, as well as the well performance comparison before and after the implementation both in terms of production and sand count.
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