Hydrate Risk Management in Gas Transmission Lines

Abstract

Gas hydrates are ice-like solids that can readily form and restrict flow in high-pressure natural gas transmission lines. The use of antifreeze thermodynamic inhibitors dominated production systems throughout the 20th century, where most research necessarily focused on measuring and predicting the hydrate phase boundary. In the 21st century, market competitiveness and environmental constraints have motivated a paradigm shift toward the identification and management of hydrate blockage risks, which has largely been facilitated to date through two research efforts: establishing and continuously refining mechanistic models to predict hydrate blockage formation; and exploiting critical stages within that blockage mechanism to develop novel, environmentally compatible inhibitors. This review presents a historical perspective on the development of an oil-dominant blockage mechanism and the technologies enabled by these efforts. Efforts over the past decademade possible through the collaboration between industry, the Australian government, and academiaare then summarized in the context of producing the first mechanistic blockage model for gas-dominant transmission lines, including the role of innovative high-pressure pilot-scale flowloop systems. Together, these blockage mechanisms have enabled new opportunities to develop and deploy low-dosage hydrate inhibitorsincluding the creation of new experimental capabilities that can be used to quantify occurrence probability or severity and the transient simulation tools that can leverage such knowledgethat support the ability to quantitatively manage hydrate blockage risk in hydrocarbon transmission lines. As they offer superior resolution in performance assessment to first-generation approaches, these new experimental methods offer structure–function design and optimization of low-dosage inhibitors against secondary, environmental parameters.

Hydrate Deposition Model and Flow Assurance Technology in Gas-Dominant Pipeline Transportation Systems: A Review

“…Because the natural gas dehydration process is cumbersome and has a certain retention rate, the presence of a free water phase in the pipeline is inevitable, which provides opportunities for the formation of hydrates in gas-rich pipelines (such as natural gas transmission pipelines). The gas-rich system (gas-based system) usually refers to a system where the main transport medium is gas and the system does not contain or contains a small number of liquid hydrocarbons or water (generally below 30%), which is contrary to liquid-rich systems (oil-based, water-based, and partially dispersed systems) . In gas-rich pipelines flowing from reservoirs, it is most often registered as an annular flow pattern, in which a small fraction of liquid is entrained in the gas phase and another fraction travels next to the wall, forming a ring or annulus of liquid.…”

Combined Approach to Evaluate Hydrate Slurry Transport Properties through Wetting and Flow Experiments

“…Prediction of the susceptibility of a natural gas-based system to form clathrate gas hydrates in the presence of water is a major task when developing assets or understanding their flow assurance challenges during production of natural gas, condensates, or crude oils. − A range of different test methods for experimental verification of hydrate formation pressure, temperature, and kinetics have been developed and are regularly used to study the properties of gas hydrates like the ones outlined in the recent reviews by Salmin, Estanga, and Koh, focusing on antiagglomerant screening techniques, and Almashwali et al on gas hydrates in oil-dominated systems . The methods mentioned in the literature focus on direct determination of the plugging potential for both uninhibited and inhibited gas hydrate systems and determination of the inhibition degree as well as delay in hydrate formation as a function of subcooling.…”

“…Gas hydrates constitute the largest problem by an order of magnitude relative scaling, wax and asphaltene precipitation . Therefore, the understanding of their properties and ability to predict possible risks of plugging is one of the main flow assurance challenges of oil and gas producer operating fields where conditions favor hydrate formation. ,,,− If not properly managed, gas hydrates may form wall deposits, lumps, plugs, or thick slurries that can block pipelines and process equipment thus with potentially severe consequences . The traditional, conservative, and safest approach to mitigate gas hydrate challenges consists of rather costly methods such as direct electrical heating (DEH), often combined with insulation, or the use of large volumes of thermodynamic hydrate inhibitors (THIs), , usually either methanol or glycol.…”

Investigating hydrate formation and flow properties in water-oil flow systems in the presence of wax

“…On one hand, hydrates are ice-like crystalline compounds formed by gas molecules (including methane, ethane, propane, and so on) and water molecules under certain thermodynamic conditions, which take the shortest time from formation to provoking pipeline plugging (Hassanpouryouzband et al, 2020). Hydrate formation is regarded as the most important issue among flow assurance problems (Song et al, 2017;Aman, 2021;Chen et al, 2022). On the other hand, the complicated composition of products provides sufficient conditions for the coexistence of multiple flow assurance issues (Gao, 2008;Liu et al, 2019).…”

“…As for the mitigation strategies to handle pipeline plugging due to the coexistence of wax and hydrates, methods that have been developed to prevent hydrate plugging, including the traditional thermodynamic method and the risk management strategy (Sloan et al, 2010;Hassanpouryouzband et al, 2020;Aman, 2021;Zhang et al, 2022), could provide significant insights. The traditional thermodynamic method focuses on the complete avoidance of hydrate formation where heating, insulation, or injection of thermodynamic hydrate inhibitors (THIs) is adopted (Sloan et al, 2010;Hassanpouryouzband et al, 2020;Shi et al, 2021).…”