Kick control when drilling high pressure wells (philosophy, drilling procedure and well control equipment)
1 Well control philosophy
The BOP and surface system, including the drillstring, should be pressure rated (and tested, except for the drillstring) to safely withstand pressure conditions created by a full gas column originating from the highest pressure zone exposed in the open hole. This means that it is always possible to safely contain the well at surface.
If equipment difficulties should arise at any stage of the kill operation, pumping should be stopped and the well closed in immediately, until the problem is rectified. During any closed-in period, the volumetric method should be employed in order to maintain constant bottom hole pressure and to allow gas to expand as it migrates to surface.
During any well control operation, the kill rate should never exceed the capacity of the well control equipment in use. If capacity/design specification of equipment is, or is liable to be exceeded, the well should be closed in and the killing operation re-started at a rate commensurate with the equipment. Procedures to avoid exceeding equipment limitations by adjusting pump speed shall be prepared and should focus on:
- mud-gas separator capacity
- pressure/low temperature down stream of the choke.
When a kick is being circulated out, pumping should be stopped as soon as 75% of the volume required to displace the influx to the wellhead is reached. The killing operation should be continued at a lower pump rate which will ensure that equipment limitations are not exceeded.
2 Drilling procedures
The following procedures are emphasised and shall be adhered to when drilling high pressure wells:
- The drilling rate shall be controlled in such a way that the Rate of Penetration (R.O.P.) will not result in a value larger than:
- LAG TIME x R.O.P.=6 m (20 ft).
- A drop in sub (DIS) shall be used in the string. The dart shall be dropped and checked to be in place prior to pulling out, except when making a short check trip.
- The Contractor toolpusher and Company drilling supervisor shall witness pulling out of hole operations for the first 10 stands and when in open hole. Pulling out of hole operations shall not commence before both persons are present on the drilling floor.
- After each check trip, the hole contents shall be circulated. If it is suspected that an influx might have entered the well and is being circulated out, circulation should be done over the choke.
- A top drive or circulating elevator should be available to assist in pumping out of hole when required.
- A cored interval shall not exceed 10 m (30 ft) per roundtrip in order to minimise the chance of encountering a kick whilst tripping due to gas coming out of solution from the core. The well should be circulated several times during pulling the coring assembly out of the hole.
3 Well control equipment
Equipment requirements for high pressure wells are as follows:
- The BOP stack pressure rating shall be at least 10% higher than the maximum anticipated wellhead pressure that could be encountered during a well control situation.
- The temperature rating of all BOP elastomers exposed to well fluids shall be higher than the maximum anticipated temperature at the wellhead/BOP stack for a continuous exposure of at least the expected duration of the well. The elastomers shall also be certified to withstand the anticipated peak temperature/pressure for at least one hour. (The peak temperature is the temperature which could be reached when uncontrolled flow through the choke line has to be allowed for one hour).
- All primary pressure containment equipment shall be selected for H2S service.
- Drillstring design should be based on the maximum anticipated annular pressure acting at any point along the hole and the hydrostatic head of the fluid column inside the string (without applying any surface pressure).
- All surface equipment subjected to well pressure must have at least the same pressure rating of the BOP stack.
- A temperature/pressure sensor shall be installed upstream of the choke to be able to assess the risk of hydrate formation in the choke line.
- A temperature/pressure sensor shall be installed downstream of the choke to be able to assess the risk of hydrate formation downstream of the choke and to monitor the low temperature of the choke manifold to ensure that the system is operated within the defined pressure/temperature limitations.
- A glycol injection system shall be installed upstream of the choke to prevent hydrate formation. Glycol injection at the subsea BOP stack may also be considered to prevent hydrate formation in the choke line.
- Variable Bore Rams (VBR's) shall not be used in 103,500 kPa (15,000 psi) WP or higher rated BOP stacks, if maximum anticipated wellhead pressures in excess of 69,000 kPa (10,000 psi) could occur during a well control situation.