Top

IWCF Well Control for Combined Surface/Subsea BOP Level 3,4

Course Outline

  • Day 1
    • The impact of a well control incident
    • The need for well control training and assessment
    • Factors that affect hydrostatic pressure
    • Hydrostatic pressure calculations
    • Formation pore pressure
    • Formation pore pressure as the lower limit of the mud weight window
    • The effects of water depth on formation fracture pressure
    • Fracture pressure
    • Fracture pressure as the upper limit of the mud weight window
    • Factors that can influence primary well control
    • Pore and fracture pressure estimation and the potential impact on primary well control
    • Secondary well control
    • Appropriate secondary well control equipment selection
    • The well barrier elements in well operations
    • The principles of different well barrier element types
    • Barrier terminology
    • Verification of well barrier elements
    • The criteria to test barrier elements
    • Documentation for well barrier tests
    • The correct action to take when a well barrier element test fails
    • How to verify the continued integrity of the well barrier envelop
    • Risk management
    • The Management of Change (MOC) process
    • The importance of checklists for operations with well control implication
    • The need for well control drills
    • The management of nonshearable and nonsealable tubulars through the BOP
    • The effect of fluid properties in the riser, booster, choke, and kill lines
    • The effect of riser margin on bottom hole pressure
    • The causes of kicks
    • The consequences of failing to keep the hole full
    • Factors that affect fluid density
    • Operations which can reduce hydrostatic head
    • Gas cutting of drilling fluid
    • The causes of gas cutting
    • The potential causes of lost circulation
    • The actions to take in the event of losses during normal operations
    • The possible consequences of losses on riser integrity
    • The causes of swabbing and surging
    • The consequences of swabbing and surging
    • Downhole swabbing and surging from the vessel motion on
    • The tripping process The risks associated with tripping
    • Actions to take when there are deviations from predicted trip tank volume
    • The actions to take after trip sheet evaluation shows an influx
    • Common tripping practices influx in the tubular
    • Homework
  • Day 2
    • Homework revision
    • Kick warning signs while drilling and/or circulating
    • Kick warning signs when tripping
    • Actions to take after recognising a kick warning sign
    • Kick indicators and the importance of early kick detection
    • The interpretation of well flow-back (for example finger-printing’ and trend analysis(
    • The effect of rig motion on detecting kick indicators
    • Shallow Gas
    • The consequences of shallow gas kicks
    • Prevention of shallow gas kicks
    • The requirements for operations in a shallow gas zone
    • Managing shallow gas flow
    • implications of drilling top hole with or without a riser
    • The methods to identify and minimize the impact of a shallow gas kick
    • The use of barite
    • Bottom hole circulating pressure and Equivalent Circulating Density (ECD)
    • The relationship between pump pressure and pump speed
    • The relationship between pump pressure and mud density
    • The process of taking Slow Circulation Rates(SCR)
    • The factors that influence selection of slow circulating rates
    • How to establish choke line friction when using a subsea BOP
    • The purpose of a Leak Off Test (LOT), and the difference between a LOT and a Formation Integrity Test (FIT)
    • How to perform a LOT or a FIT
    • The pressure versus volume graph from the LOT or FIT data
    • How to select MAASP from LOT/FIT results
    • When and why MAASP must be recalculated
    • The principles of kick margin/tolerance/intensity and how it is applied to well operations
    • The different types of influx and the hazard they present
    • How an influx can change as it is circulated up a well
    • The importance and use of the gas laws
    • Influx migration
    • The effects of influx fluids on the primary fluid barrier
    • The solubility of hydrocarbon, carbon dioxide and hydrogen sulphide gases when mixed under downhole conditions with water based or (pseudo) oil based drilling fluid
    • The behaviour of dissolved gas in different drilling fluid
    • types when circulating the influx to surface including the effects of temperature and pressure
    • The impact of downhole conditions on the hydrocarbon gas state (gas or liquid influx)
    • The actions required to mitigate the effects of gas break out
    • The behaviour of a gas influx as it circulates a horizontal well
    • The effects of gas expansion in the riser
    • The actions to take with gas expansion in the riser
    • Homework
  • Day 3
    • ​​​​​​​Homework revision
    • A suitable shut-in procedure if a primary barrier fails
    • Monitoring the well after it is shut-in
    • The actions to take with gas in the riser above the BOPs
    • The hard shut-in method
    • How to confirm if well closure is successful and the actions to take if not
    • When and how to hang off the string in a well control situation
    • Wire line movement effect on BHP
    • Shut-in procedures while wire line logging operation
    • The limitation of BOP during wire line operations
    • 5 recording parameters when shut-in well
    • Obtaining and interpreting shut-in pressures
    • Trapped pressure
    • The SIDPP with a float valve in the drill string
    • limitations of pressure gauges and different readings on rig
    • using of dedicated gauges for SIDPP and SICP
    • gas migration and causes of pressures increase and actions taken
    • Controlling BHP when an influx is migrating
    • Standard well control methods
    • The difference between controlling and killing a well
    • Selection of kill pump rate
    • The appropriate kill methods with the bit on bottom
    • The appropriate course of action to take when not on bottom
    • Maintaining constant BHP
    • The effect of Choke Line Friction (CLF) on BHP when starting and stopping circulation
    • The effect of CLF on BHP when changing pump speed
    • The measures to mitigate the impact of CLF
    • when starting and stopping circulation
    • How to reduce well annular pressure if MAASP (at the well weak point) is approached
    • Maintaining constant BHP when changing pump speed the driller's method
    • the wait and weight method
    • The actions required to establish kill mud weight in the riser and associated lines
    • The actions required to safely remove gas trapped in the BOP
    • Complete a kill sheet based on given vertical well data.
    • The principles of the volumetric process
    • The procedure required for controlling a well with the Volumetric Method
    • When the Volumetric Method is the appropriate well control method
    • The principles of the Lubricate and Bleed Method
    • The procedure required for controlling a well with the Lubricate and Bleed Method
    • When the Lubricate and Bleed Method is the appropriate well control technique
    • The principles of stripping
    • The procedure required to safely strip into a well
    • The factors which limit or complicate the ability to strip in the Hole
    • Factors that increase the risk of kicks while casing operation
    • how to reduce surge and swabbing pressures
    • The limitations of selffilling float systems
    • Monitoring returns when running and pulling casing
    • The calculation of displacements when tripping casing line
    • actions if losses happen when running casing
    • The changes to BHP during a cementing operation
    • cement job result
    • events result from entering formation fluids to casing or open hole after a cementing operation
    • The actions to take if a well starts to flow during a cementing operation
    • The steps to shut-in a well when running casing
    • The concept and implementation of well control drills as specified by API standards
    • Indications that MAASP is exceeded during a well control operation
    • Indications of downhole or surface problems that can arise during well control operations
    • How to detect when gauges are malfunctioning
    • The actions to take when operating limits are being reached or have been reached in a MGS
    • Leak identification and responses to well
    • control equipment failure
    • What hydrates are and the conditions likely to lead to their formation
    • Hydrate prevention and removal
    • Monitoring and managing losses during a well control event
    • PRACTICAL TRAINING ON SIMULATOR
    • Homework
  • Day 4
    • ​​​​​​​Homework Revision
    • BOP Stack and configuration.
    • BOP function, configuration and the well control operations that can be carried out
    • The overall pressure rating requirements of a BOP stack
    • The configuration of the Marine Riser, Lower Marine Riser Package (LMRP) and subsea BOP
    • The operational limits associated with particular BOP ram equipment
    • changing ram equipment
    • The function and operating principles of ram locks
    • The operating principles of BOP blind/shear equipment
    • Shear ram operational procedures
    • Shear ram operational procedures annular preventers
    • The deterioration and failure of annular preventers in service
    • How hydrostatic pressure can affect annular preventers
    • The application of the annular manufacturer data and well bore pressure
    • The optimal location and size of side outlet valves on a BOP stack
    • The importance of correct gasket selection and make up procedures
    • The two most common types of diverter
    • The principles of diverter operations
    • The operating mechanisms of common types of diverters used
    • The different types of safety valves
    • The application of the IBOP The capabilities and limitations of using float/flapper valves in the string
    • DPSV installation during tubular running operations
    • The alternative circulating routes to the well and through the choke manifold during well control operations
    • The operating principles and limitations of adjustable chokes
    • The operating principles and limitations of a Mud Gas Separator (MGS)
    • The operating principles and the role of a vacuum degasser
    • The importance of the procedures for maintaining and testing BOP stack and choke and kill manifolds (with reference to API standards)
    • The required frequency and test values of BOPs and well control equipment during well operations
    • Monitoring the nonpressured side of the barrier being tested
    • The inverted test ram in a subsea BOP stack
    • the pressure test requirements for DPSVs, Kelly cocks and IBOPs
    • The required frequency and test values for DPS
    • The required BOP operating pressures and closing times
    • Pressure and strength ratings for equipment used to test well control equipment
    • the function test and frequency requirements for BOP
    • The correct procedures to test diverter systems
    • The frequency and test values required for diverter systems
    • The principles of inflow testing
    • Factors to be considered during an inflow test
    • Mitigations to minimize the kick size if the test should fail
    • The procedures required for an effective inflow test
    • BOP Control Systems
    • The general operating principles of the remote control panel
    • The normal operating pressures and stored volumes contained in the BOP control system
    • The normal operating pressures and stored volumes contained in the BOP control system
    • The purpose and criteria for a successful accumulator drawdown test
    • How to confirm if a specific function has successfully operated
    • Possible functional problems during BOP/Diverter operations
    • BOP/Diverter operations
    • BOP/Diverter operations The general operating principles of subsea BOP control systems
    • The general operating principles of the remote control panel with a subsea installed BOP
    • How to confirm if a specific function has successfully operated on a subsea BOP
    • Functional problems during operations of a subsea installed BOP
    • The purpose of having accumulator bottles at the subsea BOP
    • The secondary closure systems and emergency device that are installed on the subsea BOP stack (with reference to API RP 53)
    • Homework
    • PRACTICAL TEST ON SIMULATOR-​​​​​​​

Download Attachment

Sorry , there is no schedules (content or dates or details ) for this course.

Share