Well Control Driller Rule

Well ControlWell Control

Training courseTraining course

Module 1Module 1

Introduction to Well Control

Importance of Well Control

• Provides a direct threat to the safety of the drilling rig and its personnel.

• Well control problems are costly in terms of time and money.

• Environmental Damage• Increased risk when drilling in unexplored areas

with unknown pressure regimes.• Prevention is always better than a cure.• Time is of the essence

Prevention of Blowouts

• Alert and well trained crews– Knowledge on causes of kicks– Knowledge of warning signs– Shut-in responsibilities– Equipment– Trained crews to properly operate

equipment

Rules and Regulations

• Operators and rig team members must comply with all government regulations.

• Regulations are in place to ensure protection of workers, natural resources and the environment.

• Supervisors, rig managers and drillers must be certified in Blowout Prevention and Well Control Training.

HSE&

UKOA

Rig Team Responsibilities

DrillerKick Detection and Well Shut-InSupervising Drill Crew During Well Control Operations

Floorhands, Derrickhands, Shakerhands, and All Crew MembersRemain Alert to Kick Warning SignsReport to Assigned Station Bill During Well Control Operations

Mud LoggersReport Indicators of Formation Pressure Increases to Driller and Operations SupervisorMonitor and Record Circulating System During All Operations

Each Member Has an Important Role in Well Control

Rig Team Responsibilities

ToolpusherEnsure that the Driller and Crew are Properly DeployedRemain on Rig Floor During Start of Tripping OperationsRemain on Rig Floor During Start of Kill OperationsBrief Crews Prior to Crew Change of All OperationsFor Offshore Operations - Inform Captain or OIM of Well Control Operations so that Emergency Marine Procedures can be Initiated Properly

Operator’s SupervisorOverall Responsibility for Well ControlEnsure that All Team Members know Their ResponsibilitiesKeep Lines of Communication Open Among all Team MembersBrief all Team Members of Planned Operations

Service PersonnelKnow Assigned Duties for Emergency Conditions

Each Member Has an Important Role in Kick Prevention

Your Role in Well Control

• Data Engineer must be able to recognise the signs of a developing well control situation.

• Early detection enables the driller to close in the well quickly and minimise the danger.

• Important to understand theories and procedures as you are expected to stay at you post during a well control situation.

• You will be expected to check calculations and be pro active in supporting the operation.

Basic PrinciplesBasic Principles

Key Terms• Hydrostatic pressure ,BHP• Surge/Swab Pressures• Dynamic pressure, BHCP• ECD• Pore pressure• Normal pressure• Fracture pressure• Overpressure• Underbalance• Under pressure

Hydrostatic pressureHydrostatic pressure

Hydrostatic pressure is the pressure exerted by the weight of a static column of

fluid. It is a function of the height of the column and the fluid density only

May be called Bottom hole pressure (BHP) if combined with pressures induced by pipe

movement

Surge and Swab PressuresSurge and Swab PressuresFrictional pressure drops due to pipe

movement. May be + or – depending on direction of movement

Magnitude in static mud depends on.

• Wellbore geometry• Mud properties • Running speed

Circulation Friction Losses

1. Mud Properties2. Measured Depth3. Size of the Drill String4. BHA Components5. Nozzle Sizes6. Annular Clearance7. Circulation Rate8. Pipe Movement9. Pipe Rotation10. Surface Equipment11. Cuttings Weight

Total Friction Loss

Mud Pumps

Drill String Safety Valve

Dynamic pressureDynamic pressureBottom Hole Circulating PressureBottom Hole Circulating Pressure Hydrostatic + the additional pressure exerted on the

bottom of the hole by the movement of the fluid column.

The increase in pressure is due to annular friction and the momentum of the mud. Usually expressed in psi

Magnitude of BHCP depends on

• Annular geometry• Mud properties• Flow rate• Pipe rotation• Pipe Movement• Cuttings Weight

Effective Circulating Density Effective Circulating Density (ECD)(ECD)

When the BHCP is converted to an equivalent mud weight it is known as the

ECD

Equivalent Circulating Density

BHCP

=TV Depth (ft) x 0.052

Operation Bottom Hole Pressure EMD/ECD

Pump OffBHP = Hydrostatic Pressure = BHP ÷ TVD ÷ 0.052

Trip Out BHP = Hyd Press - Swab Press = BHP ÷ TVD ÷ 0.052

Trip In BHP = Hyd Press + Surge Press = BHP ÷ TVD ÷ 0.052

Equivalent Mud/Circulating Density

Drilling BHP = Hydrostatic Pressure + APL = BHP ÷ TVD ÷ 0.052

Equivalent Mud/Circulating Density

Depth: 12,100 ft Mud Weight: 16 ppgAnnular Pressure Loss: 300 psiSwab Pressure: 250 psiSurge Pressure: 400 psi

Operation

Pump Off

Trip Out

Trip In

Drilling

HP = 12,100 ft x 0.052 x 16 ppgHP = 10,067 psi

= HP ÷ TVD ÷ 0.052= 10,067 psi ÷ 12,100 ft ÷ 0.052= 16 ppg

BHCP = (12,100 ft x 0.052 x 16 ppg) + 300 psiBHCP = 10,367 psi

= BHCP ÷ TVD ÷ 0.052= 10,367 psi ÷ 12,100 ft ÷ 0.052= 16.5 ppg

Bottom Hole Pressure EMD/ECD

BHP = (12,100 ft x 0.052 x 16 ppg) - 250 psiBHP = 9817 psi

BHP = (12,100 ft x 0.052 x 16 ppg) + 400 psiBHP = 10,467 psi

= BHP ÷ TVD ÷ 0.052= 9817 psi ÷ 12,100 ft ÷ 0.052= 15.6 ppg

= BHP ÷ TVD ÷ 0.052= 10,467 psi ÷ 12,100 ft ÷ 0.052= 16.6 ppg

Reverse CirculatingReverse CirculatingBullheading can increase the BHCP upto

10x that of normal circulation due to increased frictional pressure losses from

the drillstring.

Always Reduce flow rates when reverse circulating.

Pore pressurePore pressure

Pore pressure is the pressure of the fluid contained in the pore spaces of sediments

or the rocks. It is also called formation pressure

Normal pressureNormal pressure

Also referred to as Normal Formation Hydrostatic Pressure. If no barriers occur to prevent the free movement of fluids within a

formation, then it is reasonable to assume that the pore fluid will be homogeneous through all formations from the surface down. In offshore

wells the normal pore fluid is therefore expected to be the local sea water.

Fracture pressureFracture pressure

A formation can be made to fracture by the application of fluid pressure to overcome the

least line of resistance within the rock structure. Normally fractures will be

propagated in direction perpendicular to the least principal stress. Which of these three

stresses is the least can be predicted by the fault activity in the area.

Measures Horizontal Stress

Leak-Off TestLeak-Off Test

Leak-off

Pump Off

Initial Shut-in Pressure

Minimum Horizontal Stress (Sb)

FluidCompression

Linear Increase

Pre

ssu

re

Volume Pumped (litres)

0 10 20

Shut-in Time (Minutes)Record every minute for20 minutes or until pressure stabilizes.

Pre-existing FracturesOpened by ECD

OverpressureOverpressure

Subsurface pressure that is abnormally high, exceeding hydrostatic pressure at a given depth. Abnormally high pore pressure can occur in areas

where burial of fluid filled sediments is so rapid that pore fluids cannot escape, so that the pressure of the

pore fluids increases as overburden increases. Drilling into overpressured strata can be hazardous

because overpressured fluids escape rapidly, so careful preparation is made in areas of known

overpressure.

UnderpressureUnderpressure

Any pressure which is less than the local normal pressure is deemed to be

underpressure.

Commonly Underpressure is caused by depletion due to production.

UnderbalanceUnderbalance

Underbalance is of far more importance than overpressure during drilling operations.

This occurs where the pore pressure is greater than the mud pressure. The

resulting pressure imbalance provides a driving force which can cause fluids to flow from the formation into the well bore, or for the walls of the well to be pushed into the hole. The result is a fluid influx or stuck

pipe.

Pressure GradientsPressure Gradients

Pressure Gradient (psi/ft) = Density (ppg) x 0.052

Substance Weight Gradient

Fresh Water 8.33 ppg 0.433 psi/ft

Sea Water 8.6 ppg 0.445 psi/ft

Formation Water

Base Oil

8.9 ppg

7.2 ppg

0.465 psi/ft

0.374 psi/ft

Commonly used Gradients

Pressure Gradient is the rate of change of pressure with depth

Pressure GradientsPressure GradientsPressure Gradient = Density x Constant

Useful conversion constants

sg / m to psi/m 1.421sg / ft to psi/ft 0.433

ppg / m to psi/ft 0.171ppg / ft to psi/ft 0.052

Kg/m3 / m to Kpa/m 0.00981ppg / ft to PPTF 51.952

sg / m to bar/m 0.098sg / ft to bar/ft 0.03

ppg / m to bar/m 0.012ppg / ft to bar/ft 0.0036

Hydrostatic Pressure FormulaHydrostatic Pressure Formula

PHYD = MW x FT x 0.052

This can be rearranged to:

EMW = PHYD / (FT x 0.052)

Pressure calculations always use True Vertical Depth and

NOT Measured Depth

Hydrostatic Calculation - Hydrostatic Calculation - QuestionQuestion

What is the overbalance at the bottom of a well at 7493 ft TVD, with a MW of 9.5 ppg and a pore pressure of 3592 psi?

Give results in EMW ppg, psi/ft and SG

Hydrostatic Calculation - Hydrostatic Calculation - AnswerAnswer

Given EMW = PHYD / (FT x 0.052)

Then for pore pressure

EMW ppg = 3592 / (7493 x 0.052)

So pore pressure = 9.22 ppg EMW

As MW = 9.5 ppg the overbalance is 0.28 ppg EMW

Given PPG x FT x 0.052 = PSI

Then overbalance in PSI = 0.28 x 7493 x 0.052 = 109 PSI

And finally,

given Pressure Gradient = Density (ppg) x 0.052

So 0.28 x 0.052 = 0.0146 psi/ft

Mud Weight and Formation Mud Weight and Formation PressurePressure

• To minimise the risk of lost circulation.• To minimise the risk of differential sticking• To minimise formation damage.• To maintain an optimum ROP.

Standard drilling practice is to have the mud weight as close as possible to balance with formation pressure. Reasons for this are:

Trip MarginTrip Margin• Piston effect of swabbing requires a

safety margin between the formation pressure and mud weight.

• Trip margin is added to the mud weight to ensure swabbing does not create under balance.

• Plot pressure reduction against running speed. Using Swab/Surge Software.

• A trip margin of 250 to 300 psi is usual

TRIP MARGINS

HP = 9700 psi

9500

10,587

9900

9700

9300

Sta

rt p

um

ps

Dec

ele

rate

Acc

ele

rateD

ece

lera

te

Acc

ele

rateSTATIC STEADY SPEED STEADY SPEED STATIC STEADY CIRCULATIONSTATIC

SWAB

SURGEANNULUS FRICTION PRESSURE

TRIP MARGIN

FORMATION PRESSURE = 9137 psi

FRACTURE PRESSURE = 10,587 psi

LOST CIRCULATION / UNDERGROUND BLOWOUT

KICKS / HOLE INSTABILITY

PR

ES

SU

RE

Bottom Hole Pressure is Affected by Pipe Motion

Kicks and BlowoutsKicks and BlowoutsA kick occurs when formation fluid enters the wellbore indicating the well is in a state of imbalance. The drilling margins have been exceeded

Kicks can be controlled at the surface if caught early enough.

Blowouts occur when a kick cannot be controlled at the surface.

• Surface blowout occurs if a well cannot be shut in to prevent kicks reaching the surface

• Underground blowout. Uncontrolled flow between two formations.

One is kicking and one is loosing.

Barrier Definitions

Any system that can be used to contain pressure and well fluids within the well, wellhead and christmas tree.

Barriers may be active or latent

Active barriers are already in a condition to contain pressure and well fluids

Latent barriers are not normally in a condition which can contain pressure and well fluids. These can be come active with some sort of external intervention.

Barriers

ACTIVEConditioned mud/brineWellhead housingTubing/CasingWireline plugsRTTS packerClosed annulus valvesLubricator stuffing boxClosed tree valvesClosed BOP

LATENTOpen tree valvesOpen BOPSafety valveOpen wireline BOP’s

Well Control BarriersWell Control Barriers• Two well control barriers need to be in place at all stages of the well

Barrier Definition Objective

PrimaryFirst Line of

Defence

Control kicks with hydrostatic pressure

only.

(Normal drilling)

Drill to TD without a well control event

SecondarySecond Line of

Defence

Control kicks with hydrostatic pressure assisted by BOP’s

Safely kill the kick without the loss of

circulation

TertiaryThird Line of

Defence

An underground blowout

Avoid a surface blowout. Regain

primary well control

Causes of KicksCauses of Kicks

• Improper hole fill on trips• Drilling into “known” pressure zones with mud weight to low• Drilling into unexpected abnormally pressured formations• Loss of circulation. Fluid level not rate of loss is critical in well control• Swabbing, rapid pipe movement, balled bit• Overpressured shallow gas sands• High ROP’s in gas bearing formations, control ROP.• Loss of hydrostatic during or after cementing operations• Incomplete removal of formation fluids from the wellbore or BOP stack during testing or workover operations• Post perforation kick. Weighting up brine may cause bigger kick as lighter oil migrates reducing the hydrostatic. Well is overbalanced but still kicks.

Most CommonMost Common

Least CommonLeast Common

Warning Signs of KicksWarning Signs of Kicks•Drilling Break. Always flow check.•Increase in flow returns•Pit gain•Incorrect trip volumes. Pressure may prevent mud draining from the string.•Decrease in SPP or rise in SPM•Increasing gas values. CG , BG•Well flows with the pump off, Ballooning , Loss of ECD, Charged fractures.•Change in mud properties. > Salinity may > viscosity of mud > ECD•Increasing mud temperature•Cavings•Cutback in DxC or shale density•PWD•Gas cut mud expanding. 1200m bubble point.•Pinched bit, undergauge hole •Hookload/WOB variation, buoyancy

Kick TypesKick Types

• Two types of Kick exist:

1 Underbalance Kick – The formation pressure increases to higher than the hydrostatic

2 Induced Kick – Hydrostatic decreases to below formation pressure.

KicksKicks

• Most occur during trips.

• Legal requirement to monitor all trips.

• Most critical time is first 10 stands.

Gas MigrationGas Migration

Boyles Law - Open well with water base mud

13,410 ft

16.5 ppg

1 bbl

P1 = HP = 11,505 psi

6705 ft

V2 = 11,505 psi x 1 bbl

5752

V2 = 2 bbls

P2 = HP = 5752 psi

V2 = 11,505 psi x 1 bbl

14 psi

V2 = 821 bbls

2 bbls

821 bbls

© EnCana Corporation

Unload Point

Gas Behavior - Water Base Mud and Open Wellbore

40 bbls

20 bbls

10 bbls

Normally the Drillershould be able todetect the expandinggas with pit level andflow monitoringequipment.

UNLOAD POINT!

Length of Mud

Length of FreeRising Gas

Length of Mud = Length of Gas

Unload Depth = Length of Gas Kick x TVD


Unload Point

Gas Behavior - Water Base Mud and Open Wellbore

Normally the Drillershould be able todetect the expandinggas with pit level andflow monitoringequipment.

UNLOAD POINT!

Length of Mud

Length of FreeRising Gas

Length of Mud = Length of Gas

Unload Depth = 375 ft x 12,100 ft

Unload Depth = 2130 ft


40 bbls

20 bbls

10 bbls

Unload Point

Gas Behavior - Oil Base Mud and Open Wellbore

10 bbls

The real danger is when the bubble point depth and the unload condition depth are equal.This condition is extremely hazardous since violentunloading of the well can occurwith no warning to the Driller.

WELL SUDDENLY UNLOADS!

Bubble Point Depth

Liquid Gas in Solution“Breaks Out”

Critical InfluxVolume

=0.25 x (Bubble Point Depth)2 x Annular Capacity

Total Vertical Depth

Critical Influx Volume is the initial kick volume that will unload the mud from the bubble point depth to the surface..

Bubble point pressures range from 1500 - 5000 psi depending on the type of OBM and wellbore conditions.

Bubble Point Depth = Bubble Point Pressure ÷ MW ÷ 0.052


10 bbls

10 bbls

Unload Point

Gas Behavior - Oil Base Mud and Open Wellbore

WELL SUDDENLY UNLOADS!

Bubble Point Depth

Liquid Gas in Solution“Breaks Out”

Bubble point pressures range from 1500 - 5000 psi depending on the type of OBM and wellbore conditions.

Critical InfluxVolume

=0.25 x (3496 ft)2 x 0.0623 bbl/ft

12,100 ft.

Bubble point depth = 2000 psi ÷ 11 ppg ÷ 0.052 = 3496 ft.

= 15.7 bbls

The real danger is when the bubble point depth and the unload condition depth are equal.This condition is extremely hazardous since violentunloading of the well can occurwith no warning to the Driller.

Critical Influx Volume is the initial kick volume that will unload the mud from the bubble point depth to the surface..


10 bbls

10 bbls

10 bbls

Explosive Unloading

A small isolated bubble of gas is swabbed in (unnoticed), circulated to the surface (no expansion or further kick indications), where it expands and is also accelerated upwards by trailing bubbles of gas expanding underneath segments of mud.

The net effect is an instantaneous (a couple of seconds at most) very high gas rate that could result in a flash fire if not effectively dealt with.

Type 1


Explosive Unloading

Type 2 A slow continuous flow from a tight high-pressured

formation enters the wellbore over a long period of time undetected. The net effect of this influx is that there is a column of gas cut mud from the bit right up

to the rotary table.

The net effect is a "domino" unloading of the well, whereby a large part of the annulus is unloaded of mud. As well as enough gas at surface to cause a flash fire, the well will probably become much further underbalanced and the "tight" zone will flow faster and perhaps a second (permeable) zone will become underbalanced and will also start to flow.


Practices to Prevent Unloading

Tripping Limit tripping speeds to minimize swab / surge

Monitor hole fill in and out of the hole Drilling

Adjust detection equipment alarm as low as possible Circulate BU at any increase in gas levels No more than one “connection” in hole Flow check all drilling breaks

Be alert to activities that allow undetectable influx volumes Swabbing when picking up off bottom Drilling through gas sands Mud transfers, spills and leaks, pulling wet pipe, partial losses

Circulate bottoms up through open choke with BOP closed Especially the last 1500 - 3000 ft. of bottoms up


Gas Through Cement Kicks© EnCana Corporation

Gas Through Cement Kicks

AA

BB

Initially after cement placement, slurryInitially after cement placement, slurrybehaves as a fluid and transmitsbehaves as a fluid and transmitsfull hydrostatic pressure.full hydrostatic pressure.

Static gel strength development begins;Static gel strength development begins;meanwhile fluid is lost from cement slurrymeanwhile fluid is lost from cement slurryto permeable formations causingto permeable formations causingvolume reductions. volume reductions.


Gas Through Cement Kicks

Cement slurry static gel strength reducesCement slurry static gel strength reducestransmission of hydrostatic pressure transmission of hydrostatic pressure simultaneously as volume losses occur. simultaneously as volume losses occur. Together these factors cause loss of Together these factors cause loss of overbalance pressure, permitting gas to overbalance pressure, permitting gas to enter and percolate through the unset cement.enter and percolate through the unset cement.

CC

DDGas percolation leads to formation of a Gas percolation leads to formation of a discrete gas channel through the unsetdiscrete gas channel through the unsetcement. Gas may channel to a lower pressurecement. Gas may channel to a lower pressurezone or back to surface. Once formed,zone or back to surface. Once formed,these channels will remain in the cement.these channels will remain in the cement.


End of Module Summary -Key End of Module Summary -Key TermsTerms

• Overpressure• Pore pressure• Overburden• Hydrostatic pressure• Fracture pressure• Normal pressure• Underbalance• Under pressure

• Hydrocarbon Reservoirs• Aquifiers• Disequilibrium

Compaction• Charged Sands• Aquathermal Pressuring• Clay Diagenesis• Tectonics• Diapirism

Condition Mud Prior to Trips

Check the mud priorto trips!!

Mud Engineer and Derrickhand/Shakerhand•Should not be more than 0.1 ppg difference weight in and out

•Mud properties out should be within prescribed limits

•If returning mud/fluid is gas cut - circulate additional bottoms up and/or condition mud prior to POOH


Slugging Considerations

Have a standard procedure for slugging the pipe

Know the ‘pit gain” caused by slug falling. Don’t chase the slug with extra volume Be aware of the hydrostatic increase due to accumulated slugging.

Know how to use your “slugging” formulas

Pit GainFrom Slug

= Slug Volume x(Slug Density - Mud Density)

(Mud Density)

Depth SlugFalls

= Length of Slug x(Slug Density - Mud Density)

(Mud Density)


Slugging ConsiderationsMud Density: 16 ppgSlug Density: 18 ppgSlug Volume: 40 bblsDP Cap: 0.017220 bbl/ftSlug Length: 2322 ft

Pit Gain =(18 ppg - 16 ppg)

16 ppg40 bbls x

Pit Gain = 5.0 bbls

(18 ppg - 16 ppg)

16 ppg2322 ft x

Depth SlugFalls

=

Depth SlugFalls

= 290 ft


Mud Pumps


Establish Baseline Criteria

Measure SPR’s as high as 5 bbl/min rotating and static. Record PWD readings.

Establish baseline ECD’s while rotating and reciprocating the drill string. Record PWD readings.

Record PWD readings from reciprocating the drill string with the pump off.

Run hydraulics for swab and surge pressure correlation and effects of mud compressibility.

Record drain down volumes and pit changes when degasser and centrifuges are started.

Establish flow on connection footprint following drillout.

Baseline Conditions

A baseline well condition for mud compressibility will be established in cased hole for a number of circulating and rotating conditions just before drilling out

Baseline tests will include PWD responses. All changes in the well can be referenced to this

baseline.

Acceptable Flowchecks

• The Flow check should have monitored the well for a minimum of 15 minutes. Always rotate pipe slowly) when conducting a flow check - this will help prevent sticking and will break up the gels.

• Bleed off any drill pipe pressure before conducting a flow check.

• A decreasing trend of flow can be identified from a plot of Volume Vs Time.

• The rate and volume of flow follows the trend seen at previous flow checks.

Flow Checks During Trips

It is a good practice to check the well for flow during trips.The best times for slow checks are:

• Before pulling off bottom• After pulling the first few (5) stands• When there is a discrepancy in the trip record• Half way up the open hole• At the shoe• Prior to pulling the BHA into the BOP stack• When out of the hole• When in doubt


Gas Solubility in Oil Based Mud


A gas influx in an oil based mud will not behave inthe same manner as a gas influx in a water based mud. This is caused by the ability of gas to dissolve in anoil based mud.

This has consequences for both:

•The size of an influx when detected

•And the way in which an influx will act

These areas will be examined in this presentation



Conclusions - Whilst Circulating Bottoms Up

• In an OBM there will be very little increase in pit gain until the gas breaks out of the mud. This can lead to a very rapid pit gain

• In a WBM there will be a continual increase in pit gain as the influx is circulated out. The speed of increase will get bigger as the circulation continues

• The influx in an OBM will arrive at the surface later than it would in a WBM

• As mud is lost a secondary kick may start



Flowcheck in a Deep Well

Time ( minutes )

Pit Gain( bbl )

0

4

8

12

16

0 10 20 30 40 50 60 70

OBM

WBM



Riser Unloading

Time ( minutes )

Pit Gain( bbl )

0

4

8

12

16

20

0 5 10 15 20 25 30

WBM OBM

Hydrates


Hydrates


Inhibition with methanol



Circulating out a Drilled Kick From 6000 ft WellComparison with a 50:50 oil water emulsion mud.

• An emulsion mud acts more like an OBM than a WBM unless free gas is present

• Gas dissolves preferentially in the oil until it becomes saturated

• An emulsion mud will reach saturation before an OBM, once mud is saturated free gas will form



Conclusions - Influx Behavior

– Dissolved gas does not migrate– Negative flow check does not mean no

influx– Influx in OBM will take longer to arrive

at surface– Gas break out of OBM can be rapid

Hole Fill Requirements

Proper hole filling procedures prevents the loss of hydrostatic pressure as pipe is tripped in or out of the well

Hydrostatic Lossper ft of Pipe

Pulled

=Mud Gradient x Pipe Displacement

(Annular Capacity + Pipe Capacity)

=Mud Gradient x (Pipe Displacement + Pipe Capacity)



Pulled

DryPipe

WetPipe

(0.832 psi/ft x 0.00919 bbl/ft )

(0.364 bbl/ft + 0.01722 bbl/ft )=

= 0.02 psi/ft or 1.91 psi/std

=0.832 psi/ft x (0.00919 bbl/ft + 0.01722 bbl/ft )

(0.364 bbl/ft + 0.01722 bbl/ft )

= 0.058 psi/ft or 5.5 psi/std


Hole Fill RequirementsProper hole filling procedures prevents the loss of hydrostatic pressure as pipe is tripped in or out of the well

Proper Hole Fill Procedure Requires: Determine the maximum acceptable loss of hydrostatic between fills Use trip sheets and accurately measure mud volumes Proper manifolding of valves and equipment Responsible monitoring and communicating results


Pulled

=Mud Gradient x Pipe Displacement


=Mud Gradient x (Pipe Displacement + Pipe Capacity)



Pulled

DryPipe

WetPipe


Kick Detection

1. Stop the rotary2. Position the top drive for access/installation/operation of string safety valves.3. Stop the pump.4. Align the flowline to the trip tank.5. Engage the hole fill pump.6. Monitor the trip tank for gain or loss 10 - 15 minutes.

Well Flow Check Procedure While Drilling

If the Well Flows:

Shut In Immediately

If Well Flow is Very Slight:

Shut-in the well on the annular.

If on bottom: Circulate bottoms upthrough the choke for verificationthat no influx has occurred.

If off bottom: Strip to bottom and circulate bottoms-up.

If No Well Flow:

Resume operations andcontinue to monitor kickwarning signs.

Know the flow back volumesfor your rig’s surface lines.

Once the pumps are off.,ECD is lost. Flow may be strong. Be readyto shut-in.


Overbalance

• Overbalance controls formation pressure

• Monitor and record mud/fluid densities in and out on a continuous basis

• Overbalance is reduced when tripping out the hole because of swab pressure

• A 250-300 psi trip margin should be maintained as a minimum

• Mud densities must be increased when drilling abnormally pressured zones

Key Prevention FactorKey Points


Kick Detection

• Early kick detection minimizes the severity of the kick

• Trend monitoring is of utmost importance to early kick detection

• The rig team must communicate warning signs to appropriate supervisors to ensure kick prevention

• Detection systems such as flow show devices and pit level indicators must be calibrated regularly and maintained in proper working order



Hole Problems

• Hole problems can indicate loss of well control– Loss of circulation – loss

of hydrostatic– Torque and drag

increases– Stuck pipe – working pipe

during well control may induce loss of circulation

– Gas cut mud or contamination by H2S or CO2 can lead to loss of well control



OBM Rheology Effects


Kick Tolerance

Gas Gradient = 0.1 psi/ft

Mud Density = 16 ppg

8.5” holeTD @ 14,345 ft

9 5/8” Shoe @ 12,075’ TVD

LOT = 18 ppg

5” Drill Pipe

510 ft of 6.5” Drill Collars

The maximum volume of gas (based on a given pore pressure) that can be circulated from thewell without causing excessive mud loss at the casing shoe.

Calculate the Kick Tolerance

(Assume 0.5 ppg Kick Intensity)

1. Calculate the MASP for shoe Leak-Off

2. Calculate the maximum allowable underbalance.

3. Calculate the maximum length of gas beneath shoe (to cause SICP = MASP).

4. Calculate this volume at shut-in, V1 shut-in

5. Calculate this volume at the shoe, V shoe

6. Calculate what V shoe would be at shut-in V2 shut-in. (Use Boyle’s Law)

7. Report the Kick Tolerance as the lessor of V1 shut-in and V2 shut-in.

Kick Tolerance - worked example


1. Calculate the MASP for shoe Leak-Off

MASP = (LOT EMW - MW) x SHOE TVD x 0.052 MASP = (18 ppg - 16 ppg ) x 12,075 ft x 0.052) = 1256 psi

2. Calculate the maximum allowable underbalance.

MAX ALLOWABLE UNDERBALANCE= MASP ÷ TVD ÷ 0.052 = 1256 psi ÷ 14,345 ft ÷ 0.052 = 1.68 ppg

3. Calculate the hydrostatic pressure loss due to influx including the kick intensity.

HYD PRESS LOSS = MASP - (KICK INTENSITY x TVD x 0.052 = 1256 ppg - (0.5 ppg x 14,345 ft x 0.052) = 883 psi

4. Calculate the maximum length of gas beneath shoe (to cause SICP = MASP).

MAX GAS LENGTHshoe = HP LOSS ÷ (GRmud - GRgas) = 883 psi ÷ (0.832 psi/ft - 0.1 psi/ft) = 1206 ft


Mud Density = 16 ppgMud Gradient = 0.832 psi/ft

8.5” holeTD @ 14,345 ft

9 5/8” Shoe @ 12,075’ TVD

LOT = 18 ppg (0.936 psi/ft)

5” Drill Pipe

510’ of 6.5” Drill Collars

OH DP ANN VOL= 0.0459 bbl/ft

OH DC ANN VOL= 0.0291 bbl/ft

1256

Kick Tolerance - worked example


5. Calculate this volume at shut-in, V1 shut-in

If the gas length is equal to or less than than the drill collar length then: V1 shut-in = MAX GAS LENGTH x OH DC ANN VOL If the gas length is greater than the drill collar length then:

V1 shut-in =

LDC x OH DC ANN VOL + ((MAX GAS LENGTH - LDC ) x OH DP ANN VOL) = (510 ft x 0.0291 bbl/ft) + ((1206’ - 510’) x 0.0459 bbl/ft) = 46.79 bbls

6. Calculate this volume at the shoe, V shoe

V shoe = MAX GAS LENGTH x OH DP ANN VOL = 1206 ft x 0.0459 bbl/ft = 55.36 bbls

7. Using Boyle’s Law calculate what V shoe would be at shut-in V2 shut-in. (Use Boyle’s Law)

V2 shut-in. = V shoe x LOPSHOE ÷ HP @TVDBOTTOM

= 55.36 bbls x 11,302 psi ÷ 11,960 psi = 52.3 bbls

8. Report the Kick Tolerance as the lessor of V1 shut-in and V2 shut-in. 52.3 bbls


Mud Density = 16 ppgMud Gradient = 0.832 psi/ft

8.5” holeTD @ 14,345 ft

9 5/8” Shoe @ 12,075’ TVD

LOT = 18 ppg (0.936 psi/ft)

5” Drill Pipe

510’ of 6.5” Drill Collars

OH DP ANN VOL= 0.0459 bbl/ft

OH DC ANN VOL= 0.0291 bbl/ft

1256

Kick Tolerance - Graphical Analysis© EnCana Corporation

Plot Max AllowableUnderbalance

MASP

0.052 x TVD= =

1256 psi

0.052 x 14,345 ft= 1.68 ppg

MASP Leak-off

(Gmud - Giinflux)Max Length of Gas (MGL) =(No Kick Intensity, Swab Case)

=1256 psi

(0.832 psi/ft - 0.1 psi/ft)= 1715 ft

= 510 ft x 0.0291 bbl/ft + ((1715’ - 510’) x 0.0459 ) = 70.15 bblsPlot the Max Kick VolAllowed at Shut-in

= MGL x DPAV x Pfrac @ shoe

Phydrostatic @ TD

Plot Equivalent Max Kick Vol to Shoe @ Shut-in

=1715 ft x 0.0459 bbl/ft x 11,302 ft

=11,960 psi

74.38 bblsM

AX

UN

DE

RB

AL

AN

CE

(p

pg

)

(Vk)max1

70.15 bbls

2010 30 40 50 60

Max AllowableUnderbalance= 1.68 ppg

0

0.4

0.8

1.2

2.0

(Vk)max2

74.38 bbls

Max kick size that can be safely circulatedto the shoe without exceeding MASP = 52.3 bbls

Kick Size bbls

1.6

0.2

0.6

1.0

1.4

1.8

70

Kick Tolerant Region

Kick Tolerance - Graphical Analysis

Kick Size (bbls)


MA

X U

ND

ER

BA

LA

NC

E (

pp

g)

(Vk)max1

70.14 bbls

2010 30 40 50 60

Max AllowableUnderbalance= 1.68 ppg

0

0.2

100

(Vk)max2

74.38 bbls

52.3 bbls

Kick Tolerant Region

0.5 ppg Kick Intensity

Max kick size that can be safely circulatedto the shoe without exceeding MASP = 52.3 bbls

70

0.4

0.6

0.8

1.0

1.2

1.8

1.6

1.4

Choke Line Friction Pressure

The choke line friction pressure must be removed when circulating kicks from the well.

Remember!!

Choke line friction pressure is the amount of pressureloss when circulating at slow pump rates throughthe choke line with the BOP closed. When the well is shut-in and circulation is throughthe choke, the choke line is applying additional unwanted pressure to the formation. The amount of choke line back pressure can be determined by knowing the slow pump pressure for the system.

Choke Line Friction Pressure Should be Measured:

•After a round trip;•After any mud weight change;•After any significant change in mud properties or type;•Each time the choke and kill lines are flushed.


Mud Pumps


Slow Pump PressuresThe slow pump pressure is used a s a reference pressure when circulating kicks from the well.

Remember!!

Circulating pressure is the sum of all the friction pressures in the circulating system or flow path. When the well is shut-in and circulation is throughthe choke, the choke is used to apply “controlling”pressure to the formation. The amount of choke back pressure can be determined by knowing theslow pump pressure for the system.

Slow Pump Pressure Should be Measured:

•Each tour;•After any mud weight change;•Every 500 ft of new hole drilled;•After each BHA change or trip;•After any significant change in mud properties or type.


Mud Pumps


Slow Pump Pressures• Slow circulating rates should be pre-determined and should be based on the

following;– Rig barite mixing capability– ECD on open hole– Reaction time for choke operator– Pump & pressure limitations– Capacity of mud gas separator– Choke line friction (floaters)– Convenience and ease of use

• Pipe depth should be near bottom (within 50 ft)• Procedure:

– Position string– Rotate slowly– Reduce pump speed to desired slow circulating rate– Allow drill pipe pressure to stabilize and the driller should record circulating rate and

pump pressure from the driller’s console. Lead floorhand or AD should record circulating rate and drill pipe pressure reading from the choke panel and standpipe.


Drilling Programs

• Casing requirements

• Expected formation pressures

• Expected formation changes

• H2S potential

• Identification of loss zones

• Kick tolerance

• Stick diagram for posting in dog house as per regulations

What information should they contain

OBM Density Effects


Circulation SystemEstimating Pump Pressures

New Pump Pressure

( )New SPM

Old SPM

2= Old Pump Pressure x

New Pump Pressure

( )New Mud Density

Old Mud Density= Old Pump Pressure x


Mud Pumps


Bullheading - Drilling Wellbores

Key Points

• Used to pump influx back into formation• Depends upon:

•Amount of open hole•Influx location compared to permeable zone

• When to Bullhead•Large volume of influx•Excess surface pressure•H2S•Pipe off bottom - stripping not feasible•No pipe in hole•Surface pressures need to be reduced


Mud Pumps


Bullheading - Drilling Wellbores

Important Considerations

• Characteristics / condition of open hole• BOPE & casing rating (wear?)• Type of influx & relative permeability of

the formation• Quality of the filter cake• Consequence of fracturing open hole• Influx position


Documents

Well Control Driller Rule