Page 262 - Well Control for Completions and Interventions
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256                                Well Control for Completions and Interventions


          Table 7.3 Casing surface pressure schedule for first two stage of well kill
          bbls pumped                                         Casing pressure

          0                                                   375 psi
          50                                                  330 psi
          100                                                 287 psi
          150                                                 243 psi
          200                                                 199 psi
          218 packer fluid to surface                         183 psi
          250                                                 155 psi
          300                                                 111 psi
          350                                                 67 psi
          400                                                 22 psi
          426                                                 0 psi



          7.3.8.6 Annulus filled with kill fluid
          •  The tubing remains filled with annulus fluid (0.52 psi/ft.), therefore
             the tubing head pressure remains unchanged at 375 psi (as for the pre-
             vious step).
          •  Because the annulus is full of kill weight fluid, static casing pressure
             will be 0 psi.
          •  5731 2 (10,300 3 0.5564) 5 0 psi.


          7.3.8.7 Tubing displaced to kill fluid
          •  As the kill fluid fills the tubing through the SSD, tubing head pressure
             will drop until it reaches 0 psi. When kill fluid reaches the surface, the
             HP at the SSD will be 5731 psi, giving the 231 psi overbalance.
             Note: Although the choke should be used to control casing pressure, there will
          probably need to be adjustments made to the pump output. Good communications
          between the choke and pump operators are essential for maintaining the correct
          BHP (Fig. 7.2).


          7.3.9 Reverse circulation: worked example 2—plugged
          vertical well with heavy fluid in the annulus

          Packer fluid left in the annulus when the well was originally completed
          will often be significantly denser than would be necessary to kill the well
          after depleting the reservoir. Following on from the previous example,
          the effect of having a kill brine that is significantly lighter than the packer
          fluid is examined. The packer fluid used in this example has a gradient of
          0.67 psi/ft. and reflects the density needed to control the well at the
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