Engineered Casing Centralization Programs


Fit-for-purposed engineered casing centralization programs, based on actual downhole conditions AND drilling practices, can help to minimize the compromise between getting casing to bottom and achieving good zonal isolation. Pre and post installation analysis must be conducted to identify the main expected challenges and implement mitigating techniques. Close communication between operator and manufacturer increases the chances of success.


  • Review and evaluate previous casing centralization programs
  • Discuss with the drilling engineer past experiences in running casing in the area
  • If available, obtain relevant data from offset wells
  • Competency of formations
  • Type of formations and abrasiveness
  • Location of permeable formations
  • Location and severity of washout sections
  • Wellbore stability concerns
  • Drilling mud type (OBM, WBM)
  • Define maximum bottomhole temperature
  • Type of bottom hole assembly
  • Type of stabilizers
  • Casing running practices
  • Discuss with the production engineer zonal isolation issues or concerns
  • If available, discuss results from micro-seismic
  • Consider formation pressure windows and ECD concerns during cementing
  • Define cementing objectives


  • Centralizer OD: improves stand-off but increases drag
  • Centralization at mid-span: improves mud removal but allows couplings to increase drag
  • Installation over coupling: reduces drag but reduces removal of excess mud cake (differential pressure sticking)
  • Installation over coupling: reduces drag but reduces stand-off
  • Higher restoring forces: better stand-off but higher “stiffness”
  • Semi-rigid centralizers: higher restoring forces but lower performance in washouts
  • Polymer centralizers: lower coefficient of friction but lower wear resistance
  • Fixed to casing: overcomes drag but increases torque
  • Spiral blades: promote fluid agitation but “bulldoze” cuttings
  • Straight blades: reduced drag but less “bridging” effect
  • Two smaller centralizers versus one larger centralizer
  • Stop collars: improve positioning but take longer to install
  • Floating installation: easier reciprocation but less mud removal
  • Blade count: higher stability but lower flow by area


    • Evaluate well trajectory
    • Identify changes in: curvature, inclination angle, hole diameter, casing specifications
    • Identify tops of annular fluids
    • “Break up” the casing string in meaningful sections
    • If working with planned survey, consider artificial tortuosity
    • If working with actual survey, review slide sheet to check for possible hidden dog legs
    • Evaluate hole cleaning practices and determine the possibility of cuttings left behind
    • Run API 10D tests of the proposed bow spring centralizers in each interval; use test results in torque and drag simulations
    • Run sensitivity analysis on casing running friction factors; adjust accordingly based on intervals, under-gage, tortuosity, cuttings, etc.
    • Conduct axial load analysis, considering additional side forces from buckling
    • Identify buckled intervals and adjust centralizers accordingly

graph 2 CP

    • Analyze development of side forces during casing run and define centralizer types accordingly (check shallow doglegs.

casing program_1

  • Determine rotation requirements and select centralizer type and installation mode accordingly
  • Consider casing to centralizer coefficient of friction
  • Evaluate stand-off at mid-span
  • Evaluate changes in stand-off throughout the cement job
  • Consider spacing based on swirl length
  • Evaluate displacing efficiencies for a given stand-off profile
  • Consider perforation intervals
  • Discuss centralization program and installation procedures with field personnel
  • Conduct post installation analysis and calibration
  • Implement gradual changes based on casing running issues and zonal isolation success
  • Develop field-specific Standard Operating Procedures

Request Simulations