Abstract

Gas hydrates are ice-like crystalline compounds composed of nano-scale water cages that enclose gas molecules of appropriate diameters. Due to the frequent presence of water and light hydrocarbons, such as methane, in oil production, hydrate formation is considered a serious concern in flow-assurance. This concern grows as oil production moves into deeper water, where high pressures and low temperatures are often encountered.

To prevent hydrate plug formation, appropriate amounts of hydrate inhibitor need to be added into the water/black oil system. The current dose rate requirements of thermodynamic inhibitors are calculated based on the degrees of system sub-cooling indicated by the hydrate phase diagram. Therefore, the phase diagram of hydrate formation in black oil is central to safety and economic considerations. However, the commonly used phase boundary prediction programs have been shown to be inaccurate while good experimental data on the phase diagram are sparse due to experimental difficulties associated with black oil.

We report the use of proton NMR spectroscopy to monitor in-situ hydrate formation and dissociation in water in black oil emulsion. It was shown that with sufficient magnetic field homogeneity the water peak could be distinguished from oil/gas peaks in the NMR spectrum. When water forms solid hydrate, it becomes invisible to liquid-state NMR. It causes water peak in an NMR spectrum to decrease. Water peak height increases as hydrate dissociates. From the height changes of water peak, we can tell how much hydrate is present in the system. By this means the phase behavior and certain dynamic quantities of hydrate/oil systems can be measured. Results showed emulsion formation has an important impact on hydrate behavior in black oil.

This new technique provides an effective new means of measuring the phase behavior in oil/gas/water hydrate systems. It allows us to detect hydrate formation and dissociation by directly looking at the amount of hydrate present in the system, instead of relying on traditional pressure-temperature ramping curves. This gives a precision that traditional method cannot achieve. Results for this work can benefit deep-water flow-assurance.

Introduction

Gas hydrates are ice-like crystalline compounds composed of nano-scale water cages that enclose gas molecules of appropriate diameters. Due to the frequent presence of water and light hydrocarbons, such as methane, during oil production, hydrate formation is considered a serious concern in flow-assurance. This concern grows as oil production moves into deeper water, where high pressures and low temperatures are often encountered1. To prevent hydrate plug formation, appropriate amounts of hydrate inhibitor need to be added into the water/black oil system. The current dose rate requirements of thermodynamic inhibitors are calculated based on the degrees of system sub-cooling indicated by the hydrate phase diagram1. Therefore, the phase diagram of hydrate formation in black oil is central to safety and economic considerations. However, the commonly used hydrate phase boundary prediction programs have been shown to be inaccurate for black oil systems while good experimental data on hydrate formation in black oil are sparse2.

This content is only available via PDF.
You can access this article if you purchase or spend a download.