4. well control & kick
The functions of the well control system are
to detect, stop, and remove any undesired entrance of formation fluids into the borehole.
An undesired entrance of formation fluid into the borehole is called kick and
may occur due to several reasons
(high pressure formations,
insufficient drilling fluid density,
drillstring swab,
loss of circulation,
formation fracture,
etc). Fall 14 H. AlamiNia Drilling Engineering 1 Course (3rd Ed.) 4
5. blowout
If the undesired entrance of fluid feedbacks and the fluid continuously enters the borehole reaching the surface, it is called blowout.
Blowouts (in particular gas blowouts) are extremely dangerous and put the crew, the rig, the drilling operation, and the reservoir at risk.
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6. well control system constituent
The well control system must detect, control, and remove the undesired entrance of fluids into the borehole.
The system is composed of
sensors (flow rate, surface volume, annular and drillstring pressure, and etc,) capable to detect an increase of flow or volume in the fluid system,
the blowout preventer (BOP),
the circulating pressure control manifold (choke manifold),
and the kill and choke lines.
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7. the blowout preventer (BOP)
The BOP is a set of pack–offs capable of shutting the annular space between the surface casing and the drillstring.
Because of the diversity in shape of the annular, several different device types exist and they are normally assembled together (and in various configurations) called BOP stack.
The BOP stack is located
under the rotary table in land and fixed marine rigs,
and on the bottom of the sea in mobile and floating rigs.
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8. PRESSURE CONTROL EQUIPMENT
BOPs equipment are selected based on the maximum expected wellbore pressures.
The pressure rating, size and number of BOP components must be determined by the Drilling Engineer prior to drilling the well.
BOPs are rated by API as
3M (3000 psi), 5M, 10 M and 15 M.
For HPHT, BOPS are either
15 M or 20 M.
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9. BOP stacks
A fixed rig BOP
A floating rig BOP
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10. Sample of a land rig BOP Stack
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11. the BOP stack In subsea operations
In subsea operations, the BOP stack is installed at seabed.
The stack has several back up units in case of failure,
for example two annulars are used so that if one failed the other can be used.
This back-up system principle is applied to all the BOP components.
The subsea stack for HPHT operation
may not be part of the rig contract and
may have to be rented out separately, e.g. a 20K stack. Fall 14 H. AlamiNia Drilling Engineering 1 Course (3rd Ed.) 11
12. Annular BOP’s
The various types of BOP devices are:
Annular BOP, Blind ram, Pipe rams, and Shear rams
Annular BOP:
The purpose of the annular BOP is to shut the annular in front of any kind of drillstring equipment (except stabilizers) or even without drillstring.
The active element is an elastomeric ribbed donut that is squeezed around the drillstring by an hydraulic ram.
It is located at the top of the BOP stack. Fall 14 H. AlamiNia Drilling Engineering 1 Course (3rd Ed.) 12
13. an inside BOP
Controlling the pressure applied to the ram, it is possible to strip the drillstring in and out while keeping the annular closed (requires the use of an inside-BOP, which should be connected immediately to the drillstring when a kick is identified).
The inside BOP acts as a check valve, allowing fluid be pumped down the drillstring, but blocking back flow.
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14. Blind & Pipe rams
Blind ram:
The blind rams (normally one at the top of all other rams) allows shutting the borehole with no drillstring element in front of it. (the upper ram in the figure)
If the blind ram is applied to a drillpipe, the pipewill be flatten but no seal is obtained.
Pipe rams:
The pipe rams allows shutting the annular in front a compatible drill pipe (not in front of tool joints.)
Normally two rams are used a special spool between the two is used where the kill and choke line is connected. (the lower ram in the figure)
The use of two pipe rams also permit to snub the drillstring during the well control operation.
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15. shear rams
Shear rams:
The shear ram (normally one below the blind ram or below all other rams) can shear a drill pipe and provide seal.
This is a last resource when all other rams and annular had failed.
Circulation through the drillstring is lost and, if the shear ram is the lower one, the drillstring falls into the borehole.
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16. BOP control panels
All these safety devices
are hydraulically actuated
by a pneumatic–hydraulic system (actuators and accumulators),
which can operate completely independent of the power system of the rig.
Two control panels are normally used,
one at the rig floor,
and a remote one away from the risky area.
BOP accumulators and control panels
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17. The accumulators
The accumulators are steel bottles lined with a elastomeric bladers forming two separated compartments.
One compartment is filled with oil, which powers the BOP.
The other compartment is filled with air or nitrogen at high pressure.
The pressure of the gas pressurizes the oil across the elastomeric liner.
Rig power, during ordinary operation, keeps the gas in the accumulators under pressure.
The accumulators should be able to provide hydraulic power to close and open all elements of the BOP stack a number of times without external power.
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18. Sample of BOP control panel & the accumulator
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19. Choke Manifold
During a kick control operation, some of the BOP stack devices are actuated to close the annulus and divert the returning fluid to the choke line.
The choke line directs the returning fluid to a manifold of valves and chokes called choke manifold,
which allows to control the flow pressure at the top of the annular adjusting the flow area open to flow.
The choke manifold also direct the flow
•
to a flare (in case of a gas kick), or
•
to the pits (if mud) or
•
to special tanks (if oil)
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20. Choke manifold
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21. Sample of a choke manifold
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22.
23. data required to control of operations under way in the rig
Several sensors, gauges, meters, indicators, alarms, and recorders exist in the rig to provide all data required to control (safely, efficiently, and reliably) of all operations under way in the rig.
Among the most important parameters are:
weight on bit (WOB) and hook load,
rate of penetration (ROP),
rotary speed,
torque,
circulating (pump) pressure,
flow rate (in and out),
drilling fluid gain/loss,
mud temperature,
mud density,
total hydrocarbon gas in the drilling fluid.
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24. indication of hook load and weight on bit
Accurate and reliable indication of hook load and weight on bit are essential for
the efficient control of rate of penetration, bit life, borehole cleaning, and borehole direction.
The weight indicator works
in conjunction with the deadline anchor
using either tension or compression hydraulic load cells.
The deadline anchor senses the tension in the deadline and hydraulically actuates the weight indicator.
Most weight indicators have two hands and two scales.
The inner scale shows the hook load and the outer one shows the weight-on–bit.
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25. Weight indicator and a deadline anchor
Weight indicator
a deadline anchor
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26. weight–on–bit
To obtain the weight–on–bit, the driller perform the following steps:
with the bit out of the bottom, the drillstring is put to rotate and the weight of the drillstring is observed in the central scale;
using the knob at the rim of the weight indicator, the outer scale is adjusted so that the zero of the outer scale aligns with the longer hand.
The driller lowers the drillstring slowly observing the long hand.
When the bit touches the bottom, part of the weight of the drillstring is transferred from the hook to the bit (the weight–on–bit.)
The amount of weight transferred corresponds to the decrease of hook load, indicated by the long pointer (turning counterclockwise).
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27. control consoles
All modern rigs have control consoles that
shows all pertinent parameters in analog and or digital displays.
All parameters and operations may be
recorded in physical (paper) or
magnetic media for post analysis.
Some automated operations like
constant weight–on–bit and
constant torque are possible in most rigs.
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