TABLE OF CONTENTS Maximum anticipated surface pressure
Two methods are commonly used to determine maximum anticipated surface pressure:
Method 1: Use when assuming the maximum formation pressure is from TD:
Step 1
Determine maximum formation pressure (FPmax):
Step 2
Assuming 100% of the mud is blown out of the hole, determine the hydrostatic pressure in the wellbore:
| Note | 70% to 80% of mud being blown out is sometimes used instead of 100%. |
Step 3
Determine maximum anticipated surface pressure (MASP):
Example: Proposed total depth = 12,000 ft
Maximum mud weight to be used in drilling well = 12.0 ppg
Safety factor = 4.0ppg
Gas gradient = 0.12psi/ft
Assume that 100% of mud is blown out of well.
Step 1
FPmax = (12.0 + 4.0) 0.052 12,000 ft
FPmax = 9984psi
Step 2
HPgas = 0.12 12,000ft
HPgas = 1440psi
Step 3
MASP = 9984 ? 1440
MASP = 8544psi
Method 2: Use when assuming the maximum pressure in the wellbore is attained when the formation at the shoe fractures:
Step 1
Determine fracture pressure, psi:
| Note | A safety factor is added to ensure the formation fractures before BOP pressure rating is exceeded. |
Step 2
Determine the hydrostatic pressure of gas in the wellbore (HPgas):
Step 3
Determine the maximum anticipated surface pressure (MASP), psi:
Example: Proposed casing setting depth = 4000 ft
Estimated fracture gradient = 14.2 ppg
Safety factor = 1.0 ppg
Gas gradient = 0.12 psi/ft
Assume 100% of mud is blown out of the...
