Technical Feasibility Study of Cold Flow Using a Transient Multiphase Pipe Flow Simulator

Growing energy demand is pushing oil and gas recovery into challenging subsea environments. A primary flow assurance challenge for these operations, particularly for the long-distance tie-back developments that represent the future of the industry, is the formation of gas hydrates. These crystalline particles form under the high-pressure and low-temperature conditions found in pipelines, creating a significant risk of blockage, especially in cold subsea environments like the Norwegian Continental Shelf. This issue must be addressed as the industry moves toward more sustainable methods that reduce the energy consumption and emissions from offshore production. In this study, the application of Cold flow technology was evaluated as an energy-efficient flow assurance method for controlling the hydrate formation in offshore hydrocarbon production systems. Traditional methods for hydrate prevention, such as electrical heating, direct insulation, or the use of chemical inhibitors, often lead to high energy consumption, environmental issues and operational complexity—especially in deep water and long tieback developments. In contrast, Cold Flow technology adopts an alternative strategy by allowing the controlled formation of hydrate particles within the produced flow, while simultaneously implementing techniques to prevent their agglomeration and subsequent pipeline blockage. This is achieved through a controlled cooling process, whereby the multiphase mixture is brought into thermal equilibrium with the surrounding seawater temperature, in combination with a seeding technique that facilitates the dispersion of hydrate particles in a stable flow regime. To assess the performance of this method under real field conditions, a comprehensive simulation model was developed using the commercial advanced transient multiphase flow simulator LedaFlow. The model includes a detailed transport system from the wellhead manifold to the production platform, incorporating essential elements such as boosting pumps, insulation, heating systems to manage pressure and thermal losses. Two field development concepts—Floating Production, Storage and Offloading (FPSO) and subsea tieback—were investigated under two enhanced oil recovery (EOR) scenarios: gas injection and water injection. The simulations accounted for variations in production flow rate, gas-oil ratio (GOR), water cut over a 22-year field life. Key performance indicators such as pressure drop, required boosting pressure, temperature fluctuation, and energy consumption were calculated and compared across the different scenarios. The case study is based on a representative offshore oil field located on the Norwegian Continental Shelf, providing realistic operating conditions and infrastructure constraints. The advantages and limitations of the concept were identified and discussed, and a comparison was made against alternatives such as pipe insulation, direct electrical heating (DEH) and etc., considering energy consumption during operation. Results from the simulations revealed that Cold Flow offers considerable advantages in terms of energy savings and operational simplicity, particularly in the gas injection case, where lower water cut allows the hydrate particles to remain suspended without excessive risk of blockage. In contrast, the water injection case was not suitable for Cold Flow due to the high water content in the production stream, which led to increased hydrate formation and higher flow resistance due to high viscosity.