Gas hydrate formation during deep water offshore drilling is a well known operational hazard. Drill stem testing of gas reservoirs in deep water poses an even more hazardous potential since thermodynamic inhibition is sometimes ineffective because the well can produce more water than expected. This paper describes the formation and dissociation of a hydrate plug formed during a deepwater wildcat testing operation in the EspÍrito Santo Basin, offshore Brazil. Hydrate formation occurred despite continuous alcohol injection. The plug was formed in the annulus between the coiled tubing (CT) and the string above the mud line (1400m water depth), jamming the CT and avoiding string retrieval. Hot water was injected into the CT for plug removal without success although computer simulations showed an inflow temperature well above hydrate dissociation temperature for the given pressure. A thermochemical reaction fluid for in situ heat generation was further injected into the CT with no positive results. Since thermal methods failed in dissociating the plug, a depressurization scheme was designed involving retrieving CT by cutting it out just above the hydrate plug for allowing liquid removal from the drill string. Depressurization was successful in dissociating the hydrate plug in a relatively short time. Operational procedures, lessons learned and possible reasons for failure of thermal methods are discussed.


Hydrates are ice like compounds of gas and water. Gas hydrates are formed normally when pressure is high and temperature is low. Depending on pressure and gas composition, natural gas hydrates may remain stable well above water freezing temperature. Mechanical and physical properties of methane hydrates are very similar to that of the ice. When dissociating, hydrates generate high volumes of gas, around 160 std M3 per M3 for a methane hydrate. Once formed, hydrates are difficult to remove; it takes around twice more heat to dissociate hydrates than to melt ice. If hydrates melt in an enclosed space, pressure can built several hundred bars, well above burst and collapse pressure of standard drilling tubular equipment.

PETROBRAS became involved in a deepwater well testing operation in Golfinho Field, 1402m of water depth, in July 2004. The well was located in deep water, East of Espirito Santo State, offshore Brazil (Figure 1).

After logging the well, the decision was made to proceed with the well test. While bringing the well in, a hydrate plug was developed in the landing tubing string between the sea floor and the surface. During the initial clean up period of the well test, a hydrate plug began to form in the landing string above the sub sea test tree.

Figure 1 - Golfinho Field location (Available In full paper)

The drill stem test (DST)

DSTs are often run after intervals that look promising based on log evaluation. Formations of interest can then be evaluated under production conditions. Testing provides information that is used to determine the economic feasibility of a well prior to completion. Individual zones are temporarily isolated to evaluate important reservoir characteristics such as productivity index, permeability, skin damage, pressures, fluid properties and boundaries.

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