Bullheading of methanol into deepwater wells is a commonly used method to protect wells from hydrates during long shutdowns. A safe, but conservative wellbore protection approach (based on wellhead cooldown alone), was adopted for many early deepwater wells. This bullheading approach generally required large bullheading volumes (often exceeding 50 bbl) for each well.
However, for facilities with an increasing number of wells or with platform storage and weight limitations, this conservative approach may create significant operational problems, including crude and water quality concerns (due to the presence of methanol in the stream). Hence, in these cases, alternative operating strategies to minimize methanol usage are needed.
This paper describes an optimal bullheading strategy based upon detailed transient assessment of cooldown times of the entire wellbore, as well as upon evaluation of gas-oil-water and gas-liquid segregation boundaries. Bullheading guidelines are developed that include methanol volumes and bullheading schedule, depending on well fluids, wellbore shut-in conditions, and production conditions prior to shut-in.
This paper focuses on bullheading strategies for subsea wells; while not explicitly analyzed, the same approach can be applied to direct vertical access (DVA) wells. The paper will also address bullheading differences for subsea wells with uninsulated tubing and wells with vacuum insulated tubing (VIT).
Experimental results and models on oil, water, and gas segregation in the wellbore are discussed. Field data are shown for comparison with the simulation results.
Due to the high cost of subsea remediation and associated deferred production, protection of deepwater wellbores from hydrate1 formation and plugging is a major flow assurance concern in offshore operations. Hydrate prevention strategies are usually developed to provide protection during normal operation, start-up and shutdown operations. These strategies are based on elements of the system design, an understanding of hydrate formation mechanisms, and rigorous thermal-hydraulic modeling.
Generally, hydrate formation in the wellbore is avoided by maintaining the temperature of the produced fluids above the temperature at which hydrates can form: defined as the hydrate dissociation temperature (HDT). During normal production, reasonable production rates (> 1000-1500 bopd) usually provide enough heat from the reservoir to keep the wellbore temperatures above HDT. During an extended shut-in, the temperatures in the upper portion of the wellbore drop below the HDT. To avoid exposing produced fluids containing hydrocarbons and water to temperatures below the HDT, methanol (or another liquid) is bullheaded into the wellbore at the tree to push the produced water down to a lower portion of the wellbore that is at a temperature above the HDT.
The bullheading hydrate-prevention approach is shown schematically in Figure 1. During a long shut-in, the temperature profile down the wellbore approaches the geothermal temperature profile, which is shown on the right side of Figure 1. With this temperature profile, fluids in the upper portion of the wellbore are at temperatures below the HDT, and fluids in the lower portion are at temperatures above the HDT.