The purpose of well control and/or emergency drills is to familiarize the drillcrew with procedures that will be implemented and steps that will be taken in a well control event. Well control drills help the rig team to be more alerted and ready to warning signs; it also improves their capabilities in early kick detection.
Supervisors need to make sure that the drill is carried out in the most realistic manner possible. Remember, mother nature never tells you that she’ll kick you next Monday at 3 a.m!
Pit Drills should be performed at least once a week with each crew. Different pit drills can be listed as:
- Trip drill
- Strip drill
- Choke drill
Lubrication and Bleeding - The lubrication and bleeding method involves pumping kill fluid into the well and then bleeding gas at the surface after the fluid has fallen and settled.
Items required:- Accurate pressure gage at surface
- High pressure pump
- Method to measure volume of fluid pumped into the well.(Optional)
- Choke to bleed gas out of the well
- Kill fluid
Bullheading - Bullheading entails the pumping of produced fluids back into the producing formation and filling the tubing with kill fluid.
Items required:- Accurate pressure gage at surface
- High pressure pump
- Method to measure volume of fluid pumped into the well
- Known formation pressure and fracture pressure
- Known condition of tubing, casing, and wellhead
- Known packer depth, and depth of perfs
In some cases a circulating kill is preferred over a non-circulating one necessitating communication between the tubing and the casing. It this is the case, a means of communication between the two strings must be established. This is commonly done by one of the following methods:
- Shifting a sliding sleeve
- Pulling a gas lift dummy from a side-pocket mandrel
- Perforating the tubing
The two most common circulating methods used are the Wait and Weight and the
Drillers methods.
Items required:- Tubing or Workstring near bottom of the well
- Accurate pressure gages at surface on workstring and casing
- High pressure pump
- Method to measure volume of fluid pumped into the well.
- Choke to bleed gas out of the well
- Kill fluid
A well barrier envelope is a series of one or more dependent well barrier elements which will prevent unwanted flow of formation fluids into the wellbore.
Primary Barrier - Used during normal operations, e.g., drilling mud, a coiled tubing stripper, a workover fluid. A liquid used as a barrier must be “controllable” and “monitorable”.
Secondary Barrier - Used in conjunction with or in support of normal operations barrier or serves as a contingency, e.g., a BOP.
Closeable Barriers – Barriers which can be opened and closed as needed such as BOP’s or downhole safety valves.
Barrier Testing – In the case of a mechanical/closeable barrier, the device should be able to be tested in the direction of flow and to its rated working pressure or at the very least, to the maximum anticipated surface pressure to which it may be subjected.
When does a barrier become active?
All live well intervention work relies in mechanical barriers installed during intervention equipment rig up or already installed in completion:
- Downhole barriers: Mechanical plugs, column of fluid, etc.
- Surface barriers: Xmas tree valves, tubing hanger, tubing spool side outlet valve, etc.
The equipment pieces installed for pressure control are called containment devices. A containment devise becomes a barrier when it has been activated (by someone or automatically by fail safe mechanism absolutely closing the flow path). Therefore these devices can be called “closable barriers”.
The need to test barrier elements
Barriers must be tested to ensure correct functional operation and pressure integrity. Detailed criteria for barrier tests can be found in:
- The well program
- Operations manuals
- Industry standards including API, BSEE for US Offshore Federal Waters, and other government regulations
- Technical specifications from equipment manufacturers
- SEMS plan BSEE-regulated wells
Integrity tests are usually conducted according to API standards at a low pressure, typically 250-350 psi, and a high pressure, which can be up to the rated working pressure of the equipment.
BSEE requires a low-pressure 200-300 psi low pressure test.