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Abstract In order to meet the world's increasing demand for energy, petroleum producing companies must search for oil and gas in increasingly hostile environments. One area that shows great promise is in the deep water areas of the U.S. Gulf of Mexico. This is evidenced by increased lease sales and drilling activity that has occurred there within the last few years. As drilling moves into deeper waters, new technologies must be developed for safe and successful operations. Beginning around 1996 four projects were begun to develop dual gradient drilling, DGD, technology for use in water depths greater than 5000 ft. The four projects are Shell Oil Company's project, the SubSea MudLift Drilling Joint Industry Project, SMD, the Deep Vision project, and Maurer Technology's Hollow Glass Spheres project. Several publications have discussed the advantages that dual gradient drilling technology has over conventional deepwater drilling in the ultra-deepwaters. Although the advantages of the dual gradient projects are well documented, there has been little published on one of the major concerns expressed by all four projects. That is, how will well control differ for dual gradient drilling as compared to conventional riser drilling? This paper reports on a comparison of the well control aspects of dual gradient drilling to those of conventional riser drilling. It is based upon the work that the authors performed as part of the SMD project. Introduction Dual Gradient Drilling, DGD, is an un-conventional method of drilling in which a relatively small diameter return line, RL, is used to circulate drill fluids and cuttings from the sea floor to the rig's surface mud system (Fig. 1). During DGD the rig's marine riser is kept full of seawater. The top element of the BOP stack is similar to a rotating BOP, RBOP, which separates the wellbore and its contained fluids from the sea water in the marine riser. The mudlift system consists of a set of subsea pumps located on the sea floor, that takes suction from the annulus side of the wellbore just below the RBOP. These subsea pumps are used to lift the drill fluid and drilled cuttings from the wellbore annulus to the rig's mud system via the RL. The inlet pressure of the subsea pump has the option to operate on constant inlet pressure, constant circulation rate, or in a manual over-ride mode. The most common operational mode is to maintain constant inlet pressure equal to the seawater hydrostatic pressure. By maintaining the subsea pump inlet pressure equal to that of seawater HSP, a higher density drilling fluid can be circulated throughout the wellbore and still maintain the same bottom hole pressure as in conventional riser drilling. The higher density mud in the drillstring, along with the maintenance of the MLP inlet pressure equal to seawater hydrostatic pressure, results in an imbalance of pressure inside the drillstring and in the annulus just below the seafloor. The pressure imbalance causes the mud inside the drillpipe to freefall and u-tube out of the drillstring unless the circulation rate of the rig pumps is greater than the mud freefall rate. A typical plot of the wellbore pressures for DGD and conventional riser drilling can be seen in (Fig. 2). By maintaining the inlet pressure at sea water HSP, the wellbore effectively has a dual density mud system in which the wellbore pressure remains in the window between the formation pore pressure and the formation fracture pressure over a greater depth interval than for conventional riser drilling (Fig. 3). This increases the depth at which the next casing is required, eliminating as many as two to three casing strings (Fig. 4).