sonatrach's _well control.pdf

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Abalt Solutions

Introduction to Hydrocarbon Exploitation

Well Control

Section By Pratap Thimaiah gi n ee ri ng -W el lC on tr ol

Kick

An uncontrolled flow of formation fluids into the

wellbore during a drilling operation mainly

arising due to the formation pressure being

greater than hydrostatic pressure imposed by

mud column.

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Abalt Solutions D ri lli n g E ng in ee rin g-W e ll C on tr o l

Causes of Kick

 Insufficient mud weight

 Low level of fluid column in annulus

 Excessive swabbing

 Excessive drilling rate in gas bearing formation

 Diffusion of gas through mud cake

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Insufficient Mud weight

 Penetration of geo pressured zone.

 Accidental dilution of mud by fluid addition at

surface

 Dilution of mud by influx from aquifer exposed

to open hole.

 gradual decrease in mud density due to gas cut

and failure to degas.

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Low level of drilling fluid column

 Failure to fill hole during tripping

 Lost circulation

– Mud loss to caverns and vugs

– Penetration of depleted zones

– Mud loss to fractures as a result of surge

pressures, excessive hydraulics etc.

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Excessive swabbing

 Reduction of bottom hole pressure caused by

upward pipe movement

 Mud flows down the annulus into the open hole.

 Frictional pressure loss in the direction of

surface.

 Reduced BHP and instantaneous vacuum below

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Excessive drilling rate in Gas bearing formations

 Influx reduces mud density in annulus.

 Mud cut occurs from:

– Swabbing

– Fluid diffusion due to negative pressure

differential

– Expansion of gas as it reaches the surface.

– Air entrained in mud from the Kelly air trips.

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Pre-Kick Data

 Maximum Working Casing Pressure

– Casing and BOP are designed for different expected

pressures during each phase.

– Determined during well planning-Usually maximum

rating of BOP or 80% burst pressure of last casing

string.

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Pre-Kick Data

 Pump, String and Hole configurations

– Pump capacity

– Hole stability

– Drilling string capacity

– Annular capacity

– Casing data (size, weight, burst pressure, shoe

depth etc)

Kick Detection Techniques

 Positive Indicators

– Mud pit level/flow increase

– Incorrect hole fill up during trip

– Decrease in stand pipe pressure

– Increase in pump rate

– Increase/decrease in drill string weight

 Potential Indicators

– Increase in ROP

– Lost circulation

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Well Control Procedures

 Control Procedures Involve the following:

1. Shut in the well-follow predefined procedures 2. Observe shut in pressures and kick volumes 3. Make kill calculations for

– Formation pressure

– BHP

– Kill mud density

– Initial and final circulation pressure – Drill pipe pressure schedules – Weighting material volume required.

4. Define weighing up and circulating procedures

– Drillers method – Wait and weight method – Concurrent

– Top kill method

5. Make interpretation for influx

1. Height and density

2. annular pressure behaviour while circulating

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Well Control Equipment

 Wellheads

 Control systems

 Associated equipment

 Blow out Preventers

– Annular

– Ram Type

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Well Control Equipment

 Annular Preventer

– Doughnut shaped elastic element with bond steel reinforcement.

– Extrusion of element into wellbore is effected by upwards movement of hydraulically actuated piston.

– Element designed to seal around any shape or size of pipe and to close on open hole.

– Facilitates stripping of drill pipe in and out of well, with pressure on wellhead

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BOP

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 Majority of annular Preventer currently in use are manufactured by

– Hydril (types MSP,GK,GL,GX) – Shaffer (spherical)

– Cameron (Type D)

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 Ram Preventers

– Two Hydraulically actuated horizontally opposed rams which are either designed to seal off an open hole or annulus against pipe of specific diameter.

– Working pressure of ram preventers should be atleast equal to maximum anticipated surface pressures ,plus margin for pumping to the well.

BOP

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 Types

– Pipe Rams

 Designed to centralize and pack-off around one specific size of drill pipe or casing.

– Variable Pipe Rams  Available in different

sizes

 One set will provide back-up for two different pipe rams.  Have limited hang-off

capacity therefore depends upon tool joint size and ram range.

BOP

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BOP

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– Hanging Rams

 Pipe rams with enhanced load bearing capacities used for floating operations.

 Hardening of bearing area

– Blind/shear rams

 Used to cut pipe and seal as blind rams.  Pipe stub accommodated in a recess.

 Care should be taken that pipe body is opposite rams and not tool joint.

 Bop control systems must be adequate to shear the pipe in use.

– Offset rams

 Available for dual completions

BOP

Control Systems

 Provides means of individually closing and opening each BOP and valve conveniently, rapidly, repeatedly and at correct

operating pressure.

 Designed to operate when in

emergencies, primary rig power may not be available.

 Elements of control systems:

– Power source – Control manifolds – Accumulators

– Connecting pipe works/hose bundle and wiring

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Control Systems

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Control Systems

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Control Systems -Power Source

 Primary power source – Electrically driven pumps.

– For a 3000 psi accumulator system, pumps should incorporate a pressure switch set to cut in & out at 2800 psi and 3000 psi respectively.

– Diesel pumps used on land rigs  Secondary power source

– Air power pumps located on control manifold.

– Stand by diesel driven air compressor piped to pumps should be provided at location away from primary power source.

 Battery packs

– Where electric panels are used, a battery pack is required  Manual closing

– Extension arms and wheels should be considered for ram preventers. gi n ee ri ng -W el lC on tr ol

Control Systems-Control Manifolds

 Equipped with three control manifolds or panels

– Central Manifold

Located away from the rig floor area.

All hydraulic, air-hydraulic or electro-hydraulic Required features are

– Regulator to reduce accumulator pressure to operating pressure for ram preventers ,annular preventers and valves.

– Control handles or switches – Pressure gauges

– By pass valves

– Vent line for bleeding off accumulator fluid – Relief valve for pumps

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– Driller's Control Panel

Located on the rig floor within access. Air or electric operated

Required features include:

– Control for each BOP Stack and to adjust manifold regulators.

– Read-outs for accumulator pressures, manifold pressures and flow meters.

– Air supply pressure read outs. – Schematic showing kill & choke lines – Visual or audible warning devices

– Remote Manifold

Located at safe distance from well access Required features include:

– Controls for BOP Stack – Interlocks and covers

– Visual and audible warning systems – Schematic of BOP Arrangement.

Control Systems-Control Manifolds

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 Hydraulic fluid required to operate the BOP functions is stored in accumulators, pressurized against a nitrogen inflated bladder.

 Located near control manifold.

 Stores hydraulic energy and high rate supply of fluid for BOP functions.

 Operating pressures are 3000 psi.

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 High capacity conduits for individual functions.

 For a particular function, fluid flows from accumulators,

through regulators and directly to function.

 Control lines should be seamless steel tubing of 1 in

minimum nominal size and pressure rating equal to

working pressure of control system.

Control Systems-Pipe Works/Wiring

Associated equipment

 Mud control & Monitoring equipment

 Mud gas separators

 Drill string valves

 Rotating heads

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– Calibrated read-out and audio alarm installed in Driller’s station

 Flow line measurements – Measures flow line mud

return rate  Trip tank

– Used to fill hole during trips, measure mud volumes or water into annulus when circulation is lost or logging etc. – Types  Gravity feed  Pump type

Associated equipment-Mud control & Monitoring

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 Separates gas from drilling fluids  Provides a means for safety

venting the gas and returning usable liquid mud to active system.

 Minimizes risk for gas influx circulation during a kick without having to shut down the system  Types

– Atmospheric

 Referred to as ‘gas buster’ or ‘poor-boy’ separator.  Simple design and does not

require control valves on

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 Used to close in well on the drill pipe bore and to protect surface equipment.

 Placed on surface and may be either manual shut-off or automatic check valve type.

 Rated at same pressures as BOP & tested at same frequency.  Types

– Kelly Valves

 Upper kelly valve closes on drill string when kelly is down through rotary table and cannot be lifted.

 Lower kelly valve allows closing- in on drill string and removing kelly if required

– Float valves

 Prevents back flow during connections and flow up drill string in the event of a kick.

– Drop-in valves

 Held on surface & dropped down to a special landing sub.

 Allows pipe to be stripped to bottom and preventing further circulation

– Drill pipe safety valves

 Installed when kick occurs, allows drill string to be closed-in.

– Inside BOP

 Surface installed checked valve to close drill string bore.

 Available on rig floor as back up and installed above drill pipe safety valve

Associated equipment-Drill String Valves

 Installed above BOP and provide seal on kelly or drill pipe.

 Drive unit is attached to Kelly, locates in bearing assembly

 Applications

– Drilling with air or gas – Permit drilling

Underbalance. – Diverter for surface

hole

– Keep gas away from rotary table, important

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Kill Method-Driller’s Method

 Well shut in after the kick has occurred with appropriate shut in procedures followed.

 Influx circulated out using original mud in hole.

 Once kick is out of hole, the hole is filled with the heavier kill mud.  Two circulations:

– First circulation-remove influx – Second circulation-circulate kill mud  Advantages

– Minimum circulation – Minimum idle time

– Minimum well information required  Disadvantages

– High annular pressure if kick contains gas – Maximum time with well under pressure – Maximum time spent controlling choke

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Kill Method-Driller’s Method

Kill Method- Wait & Weight (Engineer’s) Method

Influx is circulated out by the kill mud in one cycle.

Requires manipulation of choke to maintain constant bottom hole pressure as the new mud moves from surface to bottom.

The kill may require several circulation cycles with mud density raised in stages.

Advantages

Lowest wellbore and surface pressure. Minimum time spent on choke Disadvantages

Idle time weighting up with gas migration possible. Possibility of several cycles if large mud weight increase is

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Kill Method- Wait & Weight (Engineer’s) Method

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Kill Method-Concurrent Method

 Mixes the features of Drillers & Engineers Methods.

 Applied in cases where surface pressures need to be kept as low as possible and shut-in time minimum.

 Circulation starts immediately after observing shut-in pressures using current mud weight.

 Mud weight is then increased in stages.

 As each stage of increased mud weight reaches the bit, the driller starts pumping next stage.

 When the new mud reaches the kill mud weight, circulation continues until new mud reaches the surface.

 This method requires more choke manipulation to maintain constant BHP like Engineers method.

 Advantages

– Minimum idle time – Control starts immediately

– Continuous and smooth adjustment of mud density  Disadvantages

– Slightly more complex calculations

– Maximum time spent circulating under pressure.

Well control -Without Circulation

If the influx is gas-drill string out of hole ?

 Volumetric method to bleed –off ,allowing gas to expand as it migrate.

 Most effective method when the kick occurs during swabbing.  In most cases mud weight is sufficient to prevent further influx

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Well control -Without Circulation

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Kill Fluid Gas Compressed Displace Small Amount of Kill Fluid Into Well. Kill Fluid Settles To Bottom Gas Pressure Bled Off at Surface (Process Repeated) Kill Fluid Gas Gas Kill Fluid lC on tr ol