Transient Simulation for Hydrate Mitigation Aims for Optimal Production in Kuwait Fields
Authors: Wilson Adam 
Published: October 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 182237, “Assuring Optimal Production and Enhanced Operational Efficiency Through Transient Simulation—A Case Study in North Kuwait Jurassic Fields,” by Mohammad Al-Sharrad, Kuwait Oil Company; Roshan Prakash, SPE, and Christian F. Trudvang, SPE, Schlumberger; and Noura Al-Mai, Abrar A. Hajjeyah, SPE, and Abdulaziz H. Al-Failakawi, SPE, Kuwait Oil Company, prepared for the 2016 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 25–27 October. The paper has not been peer reviewed.

In the deep high-pressure/high-temperature North Kuwait Jurassic (NKJ) fields, the pipelines connecting the wells to the processing facility are neither buried nor insulated. During the winter, the well fluid cools to below hydrate-formation temperature in the flowline, causing hydrate crystallization and even plugging. This paper presents the traditional methods of hydrate mitigation used in the NKJ fields and the way in which a transient model was initially built and continuously improved.

Challenges

Hydrate Formation. When the well forms hydrates, usually at night and early morning in winter, the field operators must wait for the ambient temperature to rise in order to melt the hydrate plugs. In general, well production declines for 6–8 hours because of hydrates. Because hydrate formation is the main cause of concern, a robust solution is needed to minimize production downtime. No proper flow-assurance study or modeling was conducted to understand the effect of water and inhibition details on the hydrate curve. To address this challenge, a predictive transient tool is needed to know in advance when hydrate will start to form, the location of hydrate formation, and the required methanol (MeOH) dosage rate to avoid hydrate formation. The current practice of hydrate inhibition is mainly based on past experience. Injecting MeOH on the basis of past experience, without knowing the optimal MeOH-injection rate, could lead to other flow-assurance challenges.

Slug Flow. Low-condensate/gas-ratio and high-water/gas-ratio wells have a tendency to create slug flow in the pipeline because of continuous changes in the phase holdups. Because of wide temperature fluctuations between night and day, the fluid in the pipeline is always in a transient state. The pipeline acts as storage because of its large volume (1,000–3,000 bbl). In the morning, when the pipeline is heated, the fluids expand and gas holdup increases in the line, which pushes the liquid to the facility and causes a surge at the facility inlet. At night, when the pipeline cools, liquid hydrocarbon accumulates in the line, increasing the liquid holdup. High-water wells always will have a tendency to accumulate water in the low-lying zones. This water generally moves as a slug. Modeling of the multiphase fluids to understand the slug behavior is required for balancing the fluid in and fluid out of the facility. Long and complicated flowline geometry further complicates the system dynamics and will affect the flow behavior.