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-​​​​​​​