Well Control Flashcards
List 5 warning signs of kicks while drilling.
Flow rate increase, well flows with pump off, pit gain, drilling break, lost circulation, drilling into a fracture, increase in torque and drag, increase connection or background gas.
While drilling a horizontal well with water base mud, a kick is taken and the well is shut in immediately without a flow check. How much of a difference would you see between SIDPP and SICP?
There should be little or no difference between SIDPP and SICP if the kick is still in the horizontal section. Gas does not migrate horizontally.
What does shut in drill pipe pressure tell you?
It is the difference between formation pressure and hydrostatic pressure in the drill pipe.
Have you been in a well control situation before? If so, describe your role and what happened.
yes. Do not rig out wire line when stuck in the hole without being shut in. Even if you think you have cemented off all the gas zones.
On a connection you notice that the off bottom circulating pressure has dropped by 1000 kPa. What would you do?
Investigate for lost circulation, gas-cut mud in annulus, dump valve stuck open, washout in string pump losing suction, leak on surface, pump washout, motor drive line twist off.
How and when is nitrogen used to unstuck pipe? How would you plan it?
when you are diff stuck.
By Directive 36, function testing Class II-VI BOP’s and HCR for an inspector requires the accumulator pumps be shut down for the test. What is the minimum accumulator pressure during the test and what is the minimun time to recharge the accumulator back to operating pressure when the pump is turned back on? What practices have you done to monitor accumulator performance?
8400 kPa and 5 minutes
With surface casing run, what should the minimum pressure test values be for high and low pressure tests on the annular, rams and choke manifold for a 21,000 kPa Class IV stack (Alberta) and manifold and what constitutes a valid pressure test?
1400 kPa low, 7000 kPa high on the annular, rams and manifold. A 10% bleed off is permitted. A valid pressure test consists of a 0 kPa pressure drop
What are the pressure testing requirements for different class BOP’s and casing strings?
Class 1 BOP’s do not require to be pressure tested - only functioned Other classes required all associated components to be tested with a 10 minute low and high test Every casing string requires a low and high pressure test immediately after cementing
Understanding the appropriate BOP’s in different thermal areas - Class 1, 2, 3 or 4?
Class 1 can be used for surface hole when hydrocarbon zones may be encountered or high watertables (artesian aquifers).
Class 1 used in low risk areas (Oil Sands Approved areas) - Directive 8, Checklist 3 posted.
Different minimum pressure ratings.
Depth ratings.
BOP Components
What is a well barrier? Give examples
Well barriers can be fluid hydrostatic pressure or a mechanical. Purpose of a well barrier is prevent formation fluid from flowing unintentionally to surface or into another formation. Barriers must be independent and tested for verification.
Primary Barrier: drilling fluid Secondary Barriers: BOPs, wellhead, casing, cement, etc.
How would you validate a barrier? Give Examples
Drilling Fluid: confirm fluid density provides adequate hystrostatic pressure to contain formation pressures
Mechanical Barrier: pressure test in the direction of flow (if possible), to maximum expected differential pressure or to regulatory requirement, whichever is higher.
What was the barrier policy of your previous employer? Or what is the the barrier policy at Husky?
Husky’s barrier policy is to have at least two independent and tested barriers available in order to control the potential flow path during well operations.
What are important considerations for well barriers?
Most operations will require 2 barriers in place at all times where potential exists for uncontrolled flow, exceptions to this normally require a risk assessment by the operator (and MOC). Barrier must withstand max pressure differential it is exposed to. Barrier location must be known and must have a positive or negative pressure test to provide verification (if practical test should be in the direction of flow) Barriers must be independent so no single barrier failure will allow flowA failed barrier must be accessible to repair without impacting the 2nd active barrier
Explain some well conditions when drilling fluid would need to be validated as a well barrier?
‘Example: 1) Drilling into over-pressure formation usually requires increasing the mud density to control fluid/gas influx. Before drilling ahead, often a short wiper trip and circulating bottoms-up is conducted to confirm drilling fluid has adequate hydrostatic pressure (trip margin) to drill ahead or trip out of hole.
‘Example 2) During MPD operations the well is circulated to kill fluid at the heel, then monitored to ensure mud density is adequate to limit ballooning and still control the well before tripping out of hole.
