Real-Time Digital Chemistry Offshore Transforms Flow Assurance Management

Managing asphaltene accumulation in offshore Gulf-of-Mexico wells is a significant challenge. Until recently there was no real-time chemical monitoring that could advise on whether chemical inhibition was making a particular well more, or less, stable. This changed with the development of real-time hardware that directly measures the ratio of asphaltene flowing in the oil. A new generation of that hardware has now been launched which meets all of the Qualification and HSE requirements for deployment on offshore platforms. A microwave resonator was designed to receive fluid at wellhead conditions, i.e., without a reduction in pressure or temperature, and the parameters of that resonator were optimized to maximize microwave intensity for typical oilfield fluids. The microwave circuitry is incorporated in an explosion-proof container with Class 1 Div 2 rated electrical and fluid connections. By combining that resonator with a solenoid that can generate a large magnetic field around a flowline, the resulting device resonates electrons within asphaltene molecules to create a unique signature that is proportional to the total asphaltene count. Estimates of oil-water cut and gas-oil ratio are also obtained as part of the processing and this combination gives the percentage of asphaltene within the oil. The use of this hardware with controlling software and cloud processing creates a unique Internet-of-Things device which can be used to optimize asphaltene-related flow assurance challenges offshore. Pressure testing up to 5ksi and 120C gives the device a working envelope well exceeding typical offshore production hardware requirements. For a fixed fluid, the computation of asphaltene ratio was shown to be independent of applied pressure. Conversely, it was found that in a live well chemical properties of fluids can change over the course of a few hours even when the surface pressure and flow-rates stay the same. In one well, the surface asphaltene percentage within an oil was seen to vary from 0.3% to 3% because of alternating deposition and erosion of an asphaltene layer that had been forming along the ID of production tubing. Over the course of a series of tests in the Middle East, it was observed that those wells with uniform asphaltene percentage were seen as less troublesome to manage compared to wells with a higher deviation. In two Permian fields subject to CO2 flooding, a geographic variation in asphaltene percentage which correlated to the long-term exposure to injected gas was observed. It has long been standard for chemical properties of fluids to be obtained by sending samples to a lab. This paper demonstrates additional value that can be obtained from getting that data in real-time, especially when viewed in the context of an overall chemical management program.