Well Control Slideshow 2014_15.pdf

8/10/2019 Well Control Slideshow 2014_15.pdf

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WELL CONTROL LAB

Dr. Tibor Szab

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Course Description

Causes of kicks, warning signs of kicks,shutting-in procedures, the risk of shallow gas,stripping operation, pressure balance in thehole, behavior of gas in the well, well controlmethods, well control equipment, BOP stackarrangements, manifolds and valves systems,

other devices, the functions and capacity ofthe accumulator unit, pressure testing of wellcontrol equipment, regulations and standards.

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Assessment

Students will be assessed with using thefollowing elements.

Attendance: 5 % Homework 10 % Short quizzes 10 %

Midterm exam 40 % Final exam 35 % Total 100%

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Grading

% value Grade

90 -100% 5 (excellent)

80 89% 4 (good)

70 - 79% 3 (satisfactory)

60 - 69% 2 (pass)

0 - 59% 1 (failed)

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Literature

T. Bell, D. Eby, J. Larrison, B. Ranka: BlowoutPrevention, 4th Ed. ISBN 0-88698-242-1. 2009.

R. Baker: Practical Well Control, 4th Ed. ISBN 0-

88698-183-2. 1998. R. Grace: Blowout and Well Control Handbook, Gulf

Publishing Company, ISBN: 0750677082.

R. D. Grace: Advanced Blowout & Well Control, GulfPublishing Company, 1994, ISBN 0-88415-260-X.

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Estimated Costs of Blowouts

Location and Event Year Cost M $

North Sea, Ekofisk Platform, Blowout 1976 56West Africa, Onshore Blowout 1978 90

North America, H2S Blowout 1982 50North America, Underground Event, Jack-Up 1985 124

S. America, Platform Blowout 1988 530North Sea, Platform Explosion and Fire 1988 1360Norvegian North Sea, Underground Blowout 1989 284Kuwait Oil Co., Al-Awda Project, Kuwait 1991 5400

Pusztaszls 34 2000 38

Csunking 233 dead, 20000 evacuationNagylengyel 282A 3000 evacuation

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PRESSURE CONCEPTSPressure Fundamentals

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The U-tube

MW - 10 ppgTVD - 10,000 ft

String Annulus

HP = MW x 0.052 x TVD= 10 x 0.052 x 10,000

= 5,200 psi

HP = MW x 0.052 x TVD= 10 x 0.052 x 10,000

= 5,200 psi

Two columns of fluid:One inside the pipe & one in the annulusThese two columns of fluid act to form a U-tube .If the MW in the pipe & annulus is the same then the mud level will same

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Hydrostatic pressure

Primary Control Hydrostatic pressure > Formation pressure

KICK (underbalance) Hydrostatic pressure < Formation pressure

Secondary Control Hydrostatic press + SIDPP = Formation

pressure

Tertiary Control Shear/seal Ram Baryte Plug

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Hydrostatic Pressure

MeasuredDepth = MD

True VerticalDepth = TVD

Static pressure of a liquid increases with density anddepth TVD

Hp = g TVD (kg/liter*0,0981 *m) = barHP = 0,052 MW TVD (lb/ft * ft) = psi

Mud gradient (MG), pressure gradient:

grad Hp = p/TVDMG = MW*0,052 (ppg*0,052) = psi/ft

MG = MW*0,0981 (kg/l*0,0981)= bar/m

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Abnormal Pressure

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Abnormal PressureGradients

Normal Pressure GradientsWest Texas: 0.433 psi/ft - 8.33 ppg 0,0981 bar/mGulf Coast: 0.465 psi/ft 9,0 ppg - 0,106 bar/m

Normal and Abnormal Pore Pressure

Pore Pressure, psig

D e p

t h , f

t

10,000 ? ?

Normal (IWCF):1,07 kg/l 0,105 bar/m

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Overpressure Due To Density Differences

Large Structures: - large anticline, dome

Hydrostatic pressure gradient is lower in gas or oil

than in water. 14


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Overpressure Due To Folding

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Overpressure Caused By Salt Dome

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Pore Pressure Development Due toUndercompaction

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20. Abnormal Pressure 411. Well Drilling Slide 18 of 41

s OB = p + s Z

s ob

p s z

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When crossing faults it is possible to go from normalpressure to abnormally high pressure in a short

interval. 20


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Determination of Fracture Gradient

To avoid lost circulation while drilling it is importantto know the variation of fracture gradient with depth.

Formation Integrity tests represent an experimental approach to fracture gradient determination.

Below are listed and discussed three theoreticalapproaches to calculating the fracture gradient.

Formation fracture pressure can be expressed: Fracturing Pressure, bar (psi), Equivalent mud weight, kg/liter, (ppg), Fracture gradient, bar/m (psi/ft).

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Fracture Gradients Determination (Theoretical )

1. Hubbert & Willis:

Where: F = Fracturing Gradient, psi/ft, P = Pore Pressure Gradient, psi/ftD = Depth, ft

D

P21

3

1F

min

D

P1

2

1F

max

2. Matthews & Kelly:

Where: Ki = Matrix Stress Coefficient , = Vertical Matrix Stress, psi,D = Depth, ft

DP

DK

F is

s

3. Ben Eaton:

Where: S = Overburden Stress, psi, = Poissons Ratio, D = Depth, ft

D

P

1*

D

PSF

Operators prefer to perform leak-off or formation-competency tests to estimatethe fracture gradient,

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Formation Integrity (Practical)

Formation strength tests can be carried out to determine:

Limit Test : A test carried out to a specified value ,always below the fracture gradient of the formation. Can be carried out in any open hole or perforated

section. Low permeable formation

Leak-off Test : carried out to the point where theformation leaks off. On Wild-Cat wells at each casing shoe On development wells, recommended

Fracture Gradient Test : A test carried out to the leak offpoint and beyond until the formation is breakdown .

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StableFracture

Propagation

UnstableFracture

Propagation Fracture Closure Phase,

Stop Pumping

Formation Integrity or Limit Test

Leak-Off Test (LOT)

LP

LOP

FOP

UFP

FPP

ISIP

FCP /MHS

LP = Limit PressureLOP= Leak-Off PressureFOP= Fracture Opening PressureUFP= Uncontrolled Fracture Pressure

FPP= Fracture Propagation Press.ISIP= Instantaneous Shut-In Press.FCP= Fracture Closure PressureMHS = Minimum Horizontal Stress

VOLUME

P R E

S S U R E

TIME

Typical Formation Breakdown Test

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Principle of Leak-off Test (LOT)

Investigate the wellbore capability with regard to Determination of maximum mud weight MAASP for safe well control operations Setting depth of the next casing,

Collect information on formation strengths Optimisation of well planning, Hole stability,

Reservoir application, Well Control

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Leak-off Test Procedure

1) Drill out shoe and 3-5 m (10 - 15 ft) of new hole

2) Circulate mud until uniform3) Pull bit inside shoe

4) Line up on high pressure low volume pump.5) Close the BOP.

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Leak-off Test Procedure

1 2 3 4

6) Pump down drillpipe or annulus low rate HP pump) max 80 litre/min (1/2 bbl/min)

7) Plot the Volume vs. Pressure

8) STOP when a change in the pressure curve is noticed

9) Repeat test verify the LO point

LOP

Pressure

Volume (Strks)

Accuratepressure gauge

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Leak Off Test Calculations

1 2 3 4

100200300400500600700800900100011001200

Stop Pumping

bbls

Shoe TVD = 1675 m (5495 ft)

Test Mud = 1.26 kg/l (10.5 ppg)

Hydrostatic Pressure of Test Mud tothe Shoe:

1.26 x 0.0981 x 1675 = 207 bar

10.5 x .052 x 5495 = 3000 psi

Fracture Pressure = Hydrostatic Pressure + LOP =

= 207 + 70 = 277 bar = (3000 + 1000 = 4000 psi)

Leak-off Pressure70 bar (1000 psi)

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Formation Strength - Limit Test

Test Objective: Confirm pressure integrity of

formation to a pre-determinedpressure.

Limitations: Limited guidance on the integrity ofthe casing shoe.

Does not quantify propertiesassociated with fracturing stresses.

Limit test provides limited

information!

Surface Limit Press. (LP)

Volume Pumped(or time @ constant pump rate)

S u r f a c e

P r e s s u r e

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Leak Off Test Low and High Permeable Formation

Leak Off Press(LOP)

Vol.

P r e

s s u r e

Initial Press

Vol.

P r e s s u r e

Final Press

High Permeable Formation Low Permeable Formation

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Leak-off Test Report

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Maximum Allowable Mud Weight

Maximum Allowable Mud Weight (kg/l) =

Example :Surface Leak-off Pressure = 50 bar (714 psi)

Casing Shoe Depth (TVD) = 1000 m (3048 ft)Mud Weight in Hole = 1,44 kg/liter (12 ppg)

Max. Allowable Mud Weight (kg/l)

)l/kg(HoleinMudWeight(m)TVDDepth,ShoeCasing

10.2x(bar)essurePr LeakOff

l/kg95.1)l/kg(44.1(m)1000

10.2x(bar)50

ppg5.16)ppg(120.052x(ft)3048

(psi)714

Field Unit:

Max. Allowable Mud Weight (ppg)

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Maximum Allowable Annulus Surface Pressure MAASPEvery time the mud weight is changed, the MAASP changes and must be re-calculatedusing Maximum Allowable Mud Weight.

MAASP =

Example:Max. Allowable Mud Weight = 1.95 kg/l (16.5 ppg)Mud Weight in Hole = 1.44 kg/l (12 ppg)Casing Shoe Depth (TVD) = 1000 m (3048 ft)

10.2)m(TVDShoex)]l/kg(HoleinWeightMud)l/kg(WeightMud Allowable.Max[

bar 5010.2

)m(1000x)]l/kg(44.1)l/kg(95.1[MAASP

Field Unit:MAASP (bar)== (Max. Allowable MW (ppg) - MW in Hole (ppg)) x Shoe TVD (ft) x 0.052

= (16.5 12) x 3048 x 0.052 = 714 psi33

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FORMATION STRENGTH DATA:

SURFACE LEAK-OFF PRESSURE FROM

FORMATION STRENGTH TEST (A) 64 bar

DRLG FLUID DENSITY AT TEST (B) 1,25 kg/l

0,1225 bar/m

MAX. ALLOWABLE DRILLING FLUID DENSITY:(A) x 10.2

(B) + SHOE T.V.DEPTH (C) 1,79 kg/l

0,1759 bar/m

INITIAL MAASP:[(C) - CURR. DENSITY] x SHOE T.V.D. =

10.2

64,00 bar

Kill Sheet CalculationMAASP

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CAUSES OF KICK

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Causes of Kick

Any time the formation pressure greater than BHP:

Penetration into overpressure formation Abnormal pressure Insufficient mud weight

Excessive drilling rate through gas sand

Swabbing surging

If height of mud column is allowed to drop Total mud loss Improper hole filling while tripping

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Causes of Kick

Early Kick Detection Closed circulation system Flow rate IN equal flow rate OUT Constant pit level

Exception

Oil base mud gas kick may be dissolved

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Kick Size

By Bill Rehm:

kick size < 3 m 3 (18 bbl) no problem ,

3 m 3 < kick size < 6 m 3 (40 bbl) good job ,

6 m 3 < kick size God help!

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WARNING SIGNS OF KICKSDrilling

Changes in drilling rate Drilling Break High pressure shale or sand ROP increases if water base mud - rock bit - drilling

break Accepted policy : drill maximum 1 m (2-4 ft) flow check

When ROP suddenly increases indicate thepossibility of kick!

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ROP As An Indicator of Overpressure

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Increased return flow rate

If the well kicks - return flow rate increases Flow measurement devices - return flow indicator

If well flowing suspected- flow check Stop drilling Kelly up Stop pump Flow check

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Flow check (WBM) in the case of water base mud Recommended up to 10 min If the well does not flow:

- During drilling flow check If the well flows: - Shut in the well,- Well killing operation


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Flow check in OBMIn the case of oil base mud Recommended up to 20 min - absorbed gas!

If the well does not flow: Bottoms-up circulation Drilling ahead 3 m (10 ft) flow check

Bottoms-up circulation short trip

if the well flows: Shut in the well - start well killing operation


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Pit gain

Positive indication - indication alarm!

Pit level indicators show and record gain/loss of mud

Information during drilling or tripping Not exact sign - mud is added or taken from pit

Quick shut-in

Rate of pit gain - indication of permeability


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High permeable formation

If slightly underbalanced good kick detection

- drilling break associated

Low permeable formation

If slightly underbalanced

- difficult detect the kick

- slow flow rate, slow pit gain

- drilling break not associated

- underbalanced - only gas cut mud appear


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Influx Rate =

The influx rate depending on: Driller resposibility:

Permeability of formation ( k = 200 mD ) NO ln Re/Rw = 2 NO Gas viscosity ( = 0,3 cp ) NO

Pressure difference ( P=42 bar (624 psi) YES / NO Penetration to formation ( L=6 m (20 ft)) YES Time of identification (0 min) YES Time the shut in ( 2 min ) YES

1440RR

ln

Lpk0,007q

we

Darcy Law

144020.3

6422000.007

Kick size = 6,24 m3 (40bbl)

3 m3/min

= 20 (bbl/min)

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Decrease pump pressure increase pump rate gas at the annulus helps for pumping U tube

Increase in rotary torque

greater increase in transition zone large amount of cuttingsIncrease in drag if pform > p mud formation close in around DP or DC (fill-up) drag forces

(water sensitive shales) during the connection or tripping


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Change in cutting size

In hard formation increase the cutting size

In shale long slivers - blinded shaker

Change in character and size of cuttings can bewarning sign.

Increase in string weight

Presence of kick reduces buoyant effect, sometimes canbe observed - Archimedes Law


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Increase the gas content in mud In mud logging - gas detection and analysis base

trend line - compared to actual data

Background gas Gas contained with cuttings gas cut mud undercompacted formation

Connection gas

Swabbing effect when the pump stopped befor kelly israised up

Trip gas - Swabbing during the trip, there is no APL


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Gas-cut mud

Often gas-cut mud not sign of kick BHP reduce not significant

Gas expands only near the surfaceVarious reasons:

Gas gets into the mud from chips

Overpressured low permeability formation, Mud pressure is close to formation pressure.


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Change in shale density

Normally increases density vs. depth

Free water squeezed out compaction

If density decreases below trend line containmore water

Overpressure suspected, at transition zone

Difficult measurement, selecting


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Change in normalized drilling rate (d Exponent)

Jorden and Shirley in Gulf Coast in 1966 Shell Co.

drilling performance date can be used to detectthe top of overpressured sediments

to identify overpressures during drilling


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Causes of Kick

Tripping

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C f Ki k


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Negative pressure waves reduce BHPIncreased by Pulling velocity High viscosity, gel strength Balling up the bit Plugged drill string Thick mud cake Small clearness between string and hole (Hole /

BHA geometry) Insufficient trip margin

Causes of KickSwabbing

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Positive pressure waves increase BHP Caused by rheology of mud Lost of circulationTo minimize the surging:

Run in at slow rate Keep mud in good condition

low viscosity, low gel strength Break circulation periodically

Eliminate the tight BHA

Causes of KickSurging

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Causes of Kick


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Swabbing

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Hi h V l S bbi


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High Volume Swabbing

BHP

Martin-Decker

VERY DANGEROUS IN TOP HOLE VERY RAPID GAS EXPANSION VERY HIGH RATE OF UNLOADING NO TIME TO REACT!!!!

Balled-up bit / stabs

Formation pack off

Fluid not draining around bit

Pulling fluid column up

MD increases

Drillstring draining > BHP reducing

Gas entering well bore

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Trip marginTrip or safety margin counterbalance swabbing effectsduring connections and tripping.

for shallow holes 3,5 bar (50 psi)

for deep holes 14-21 bar (200-300 psi) 2 x Annular Friction Losses (or 200 psi)

Mud Weight calculation from Trip Margin (TM):

TVD0981.0inargTripMMWincrementExample:

TM = 17 bar (250 psi),TVD = 3050 m (10000 ft) MW i = 0.06 kg/liter (0,5 ppg)

Causes of KickTripping

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Causes of KickSwabbing

Prevention: Low viscosity mud and low yield point Adjust pulling speed

Response & Recovery: Lower the drillstring back to bottom by stripping in Circulate bottoms up using poor-boy (free gas

separator) and degasser

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Swabbing Resolution


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Swabbing - ResolutionAfter Shut in the well P DP = P Ann - influx is below the bit

Two options: Volumetrically kill well or Perform combined

volumetric strip to below influx then circulate out influx using Drillers method.

P DP = 0, P Ann = X - influx is above the bit at drillstring annulus Circulate out influx using Drillers Method.

P DP < P Ann - influx is below the bit and around the drillstring

Two options Circulate slowly keeping P Static constant, and allow influx to

migrate up around the drillstring. Perform combined volumetric strip to below influx then circulate

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BBLS

5

10

15

TRIPTANK

10 x 90 ft stands pulled

STARTVOLUME

FINISHVOLUME

PUMP

5 bbls

FILL VOLUMES TRIPPING

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Causes of KickTripping

Roles of trip sheet Frequently or continual filling Normal conditions

hole filling after 5 stands of DP after 1 stand of DC

Good trip tank increments: / bbl if the hole not takes the correct mud volume

Flow check Tripping or stripping to bottom Bottoms-up circulation.

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LEVEL DROP DRY PIPE


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Stands pulled :10 x 27.4 m = 274 m(10 x 90 ft = 900 ft)

LEVEL DROP DRY PIPE

Casing Capacity= 39,8 l/m (.0758 bbls/ft)

Pipe Metal Displacement= 4,01 l/m (.00764 bbls/ft)

Volume of metal removed from the well.Length Pulled x Metal Displacement274 x 4.01 = 1098 litre

(900 x .00764 = 6.876 bbls)

Annular capacity inside casing with pipestill inside casing.Casing Capacity - Metal Displacement39.8 -4.01 = 35.79 litre/m

(.0758 - .00764 = .06816 bbls/ft)

Level drop inside casingVolume of metal removed Annular Capacity1098 35.79 = 30 m

(6.876 .06816 = 100 ft)

100 ft

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LEVEL DROP WET PIPE

Volume of fluid & metal removed from the well.Length Pulled x Closed End Displacement274 x 13.33 = 3652 litre

(900 x .0254 = 22.86 bbls)

Annular capacity inside casing with pipe still insidecasing.Casing Capacity - Closed End Displacement39.8 13.33 = 26.47 litre/m

(.0758 - .0254 = .0504 bbls/ft)

Level drop inside casingVolume of fluid & metal removed Annular Capacity3652 26.47 = 138 m

22.86 .0504 = 453 ft

453 ft

Pipe Capacity=9.32 l/m (.01776 bbls/ft)

Pipe Metal Displacement= 4,01 l/m (.00764 bbls/ft)

Casing Capacity= 39,8 l/m (.0758 bbls/ft)

Stands pulled :10 x 27.4 m = 274 m(10 x 90 ft = 900 ft)

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P D P lli D Pi


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Pressure Drop Pulling Dry Pipe

Mud Weight = 1.44 kg/liter (12 ppg)

(12 x 0.052) x 0.00764 x 9000.0758 - 0.00764

= 62 psi

274 m (900 ft)Length of pipe are pulled fromthe hole with no fill-up

DP Metal Displacement = 4.01 liter/m ( = 0.00764 bbls/ft)Casing Capacity: = 39.8 liter/m (0.0758 bbls/ft)

Pressure Drop Pulling Dry Pipe (bar/m):

Mud Weight (kg/l) * 0.0981 * DP Metal Displacement (l/m)Casing Capacity (l/m) DP Metal Displacement (l/m)

0158.001.48.39

01.4*0981.0*44.1bar/m

(bar/m)

Pressure Drop = 0.0158 (bar/m) * 274 (m) = 4.33 bar

MUD Weight (lb/ft) * 0.052 * DP Metal Displacement (bbls/ft)Casing Capacity(bbls/ft) DP Metal Displacement (bbls/ft)

(psi/ft)Field Unit:

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Pressure Drop Pulling Wet Pipe

Mud Weight = 1,44 kg/liter (12 ppg)

12 x 0.052 x 0.0254 x 9000.0758 - 0.0254

= 282 psi

DP Metal Displacement = 4.01 liter/m ( = 0.00764 bbls/ft)

DP Capacity = 9.32 l/m (0.01776 bbls/ft)Casing Capacity: = 39.8 liter/m (0.0758 bbls/ft)

Pressure Drop Pulling Wet Pipe (bar/m) =

MUD Weight (kg/l) * 0,0981 * DP Closed End Displacement (l/m)Casing Capacity (l/m) DP Closed End Displacement (l/m)

0711.033.138.39

33.13*0981.0*44.1(bar/m)

(bar/m

Pressure Drop = 0.0711 (bar/m) * 274 (m) = 19.5 bar

Mud Weight (lb/ft) * 0,052 * DP Closed End Displacement (bbls/ft)Casing Capacity (bbls/ft) DP Closed End Displacement (bbls/ft)

(psi/ft)

Field Unit:

274 m (900 ft)Length of pipe are pulled fromthe hole with no fill-up

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C f Ki k


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Formation fracture can cause lost circulation Can be calculated

Can be measured Leak-off Test Problem of cavernous, faulted, fissured formations

of casing shoe

Causes of KickLost circulation

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SIGNS OF ABNORMAL PRESSURE


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SIGNS OF ABNORMAL PRESSURE IN PLASTIC FORMATIONS

Increase mud returns; kick Verygood (5)

Drop in circulation pressure - SPM increase: kick Good (4)Increased drilling rate, drilling break : overpressure, kick Good (4)Increased pit level; kick Verygood (5)Change in cutting size; overpressure Good (4)

Overpulls, torque increase; overpressure Poor (3)d exponent: overpressure Good (4)Connection gas: overpressure Good (4)Trip gas, gas cut mud: overpressure Good (4)

Mud salinity, resistance: kick Poor (3)MWD (expensive): overpressure, kick Good (5)Shale density: overpressure Good (4)Return flow temperature: overpressure Very poor (2)

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SHUT-IN PROCEDURE

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SHUT-IN THEORY

Hard or Soft Shut-in : Which is the Best Approach ? Several shut-in procedures in use :

Variants of "Hard", "Soft Varying preferences results in confused drill crews

the operator and drilling contractor often haveconflicting procedures for shutting in the well.

To provide optimum safety of personnel whilemaintaining safety of the well.

Different well conditions Company policies

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SHUT-IN PROCEDURES

Hard shut-inAdvantages

The influx is stopped in the shortest possible time

Minimises the volume of the influx.

Simple and quick - there is normally no need to changeany valve alignment.

The influx is stopped in the shortest possible time

Lower shut-in casing pressure Lower annular circulation pressures

Safety of personnel and equipmen t without risk to the well

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SHUT-IN PROCEDURES

Hard shut-in Disadvantages

P ressure pulse or water hammer effect is produced inthe well-bore when the BOP is closed.

To cause possible formation damage.

Hard Shut-in or Soft Shut-in?

Depending on the company policy.

Majority of operators prefer hard shut-in.

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SHUT-IN PROCEDURES

Soft shut-in

Advantage:

Pressure pulse or water hammer effect is notsignificant when the BOP is closed.

Disadvantages: The influx is stopped in longer time, Larger volume of influx, More complicated - need more steps to shut the well in. Higher shut-in casing pressure Higher circulating pressures

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Hard Shut-in or Soft Shut-in


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Investigate the water hammer effect using a 1430 m test well.

Hard Shut in or Soft Shut inwater hammer effect (EXAMPLE)

The pulse amplitudes are 57 psi for the hard shut-in 20 psi in soft shut-in case.

The effect of the water hammer pulseis even less significant compared tothe normal annular pressure build thanat surface. 78

Hard Shut-in or Soft Shut-in - water hammer effect (EXAMPLE)


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Why is the amplitude of the pressure pulse so small ? BOP does not close instantly - effective closure time, "Tc . tr is the round trip travel time. The effect is to reduce the pressure wave amplitude by the ratio "tr/Tc 79


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SHUT-IN PROCEDURES

BOP Closing time (API)All Type of BOP 30 sec

Except:Big size annular BOP: 18 < BOP size 45 sec

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SHUT IN PROCEDURES


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SHUT-IN PROCEDURESEXAMPLE

When is a Hard Shut-in Hard ? No reduction in P for tr > Tc :

BOP closure is very rapid (fast ram operation).

Hole is very deep. Depth limit for pressure reduction:

Hole depth < 6750 m (for Tc = 10 s). For the experiment, if there was NO reflected wave :

P 120 psi P is s t i l l l ess than the f ina l shu t -in p ress ure .

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SHUT-IN PROCEDURES

Conclusions

Theory and experiment show small "water hammer"pulse in practical situations.

SOFT shut-in Little improvement to pressure pulse,

Significant effect from additional influx.

HARD shut-in

Water-hammer" smaller than shut-in pressure rise

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SHUT-IN PROCEDURES


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Possible Questions

What if contractor disagree on shut-in procedure ?

Decide at pre-spud meeting .

Higher mud velocity than during experiment ?

More important to shut-in rapidly. Pulse is larger but is still likely to be small

compared to shut-in pressure rise.

Effect of closing choke in soft shut-in ?

Lower pressure pulse is produced.

Effect is a delayed water-hammer .

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Soft shut-inll


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Drilling

Valve arrangements:

HCR is closed Choke open valve open to MGSShut-in procedure: Stop rotation - alarm

Kelly up - space out Tool Joint is not in ram BOP Stop pumps Check for flow If the well flows open HCR

Close BOP ( usually annular ) Close choke slowly (not considering if SICP exceeds

MAASP) Record SIDPP, SICP, Pit Gain, Depth

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Soft Shut-inT i i


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Tripping

Valve arrangements:

HCR is closed Choke open valve open to MGSShut-in procedure: Space out - TJ not in ram BOP Install the safety valve (kelly cock ) in open position Close safety valve (kelly cock) Flow check If the well flows - Open HCR to remote controlled choke

Close BOP ( usually annular ) Close choke slowly (not considering if SICP exceeds

MAASP) Record SIDPP, SICP, Pit gain, Bit Depth

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Hard shut-in procedures


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Hard shut in proceduresDrilling

Valve arrangements:HCR is closed Choke closed valve open to MGS

If kick occurs:

Stop rotation - alarm Kelly up - space out (Tool Joint is not in ram BOP) Stop pumps Check for flow

If the well flows - Close BOP ( usually annular ) Open HRC Read and record SIDPP, SICP, Pit Gain, Depth

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Hard shut-in procedures


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pTripping

Valve arrangements:HCR is closed Choke closed valve open to MGS

If kick occurs: Drill Pipe up - space out - Alarm Install the safety valve (kelly cock) in open position Close safety valve (kelly cock) Flow check If the well flows - Close BOP ( usually annular ) Open HRC to remote controlled choke Read and record SIDPP, SICP, Pit Gain, Depth

87

Collect Shut-in Data


88/217

Driller resposibility: Read and record SIDPP, SICP, Pit Gain and Hole Depth

Properly recording the SIDPP Properly recorded following pressure evolution , Permeability has to allow a proper pressure build up, Not taken too soon or too late, Drill stem must be full of clean mud (large kick).

Control of Drill stem is full of mud : Pump 10-40 strokes slowly, while SIDPP is constant

If SIDPP decreases Second pumping for control If SIDPP constant String is full with mud

Control of trapped pressure

88


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Low or no SIDPP and SICP

Pressure gauges are shut off

No pressure R epeat flow check

Pressure is too low Float valve in DP

89

Measurement of SIDPP and SICP withBack Pressure Valve


90/217

SIDPP

1) Start the pump with very low pump rate,

2) Continue check both Drill pipe and Casing pressures

3) If casing pressure start to increase read drill pipe pressure this is SIDPP.

90



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Supervisor resposibility:Collect Shut in data from Driller - physically check it!

SIDPP - m ust checked with evolution

not just collected from Driller SICP must be collected and checked

Pit gain - must be collected and checked

Hole depth - must be collected and checked


91

Monitor Bottom Hole Pressure


92/217

Supervisor :

Instruct Driller to monitor pressure changes on bothgauges, to avoid injection at shoe level.

Driller must instruct the supervisor befor the annularpressure reach the MAASP

The Supervisor may or may not ask the driller to bleed off.

Driller Monitor surface pressures and report to Supervisor. Driller has to do it whether or not he receives instructions

from Supervisor.

92

FORMATION PRESSURE


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Formation Pressure = Hydrostatic Pressure + SIDPP

EXAMPLE:

MW = 1.44 kg/l (12 ppg)

TVD = 2895 m (9500 ft)

SIDPP = 42 bar (600 psi)

1,44 x 2895 x 0.0981 = 409 bar

(12 x .052 x 9500 = 5928 psi)

Formation Pressure = 409 + 42 bar = 451

(5928 + 600 = 6528 psi)

600

psi

SIDPP=42 bar

Hydrostatic Pressure in Drillstring

93

Kill Mud Weight Well Data:


94/217

gOriginal MW = 1.44 kg/l (12 ppg)

Well Depth, TVD = 3048 m (10000 ft)

SIDPP = 42 bar (600 psi)

Formation Pressure = 473 bar (6528 psi)

600

psi

SIDPP42 bar

TVD = 3048 m

= 10000 ft

0981.0*)m(TVD

)bar (SIDPP)l/kg(OMW)l/kg(MWKill

l/kg58.10981.0*3048

4244.1

Field un i t :

052.0*)ft(TVD

)psi(SIDPP)ppg(OMW)ppg(MWKill

ppg16.13052.0*10000

60012

Kill Mud Weight:

94

HEIGHT OF INFLUXDetermine if the influx is below or above the drill collars


95/217

300psi

600psi

EXAMPLE 1. EXAMPLE 2.

1600 litre(10 bbl)

KICK

4000 litre(25 bbl)

KICK

Determine if the influx is below or above the drill collars

Volume of Influx to reach the top of DrillCollars = DCOH Capacity x DC Length =

= 16.8 l/m x 200 m = 3360 litre

= (0.032 bbls/ft x 656 ft = 21 bbls

95 m (227 ft)

Length DPOH = (4000 - 3360)/ 23.3 l/m = 28 m= (25 bbl - 21 bbl/0.044 = 91 ft

Length of kick = 27 + 200 = 227 m= (656 + 91= 747 ft

DCOH Capacity: 16.8 liter/m (0.032 bbl/ft)DPOH Capacity: 23.3 liter/m (0.044 bbl/ft)DC Length: 200 m (656 ft)

28 m (91 ft)

200 m (656 ft

Length of kick == 1600 /16,8 l/m = 95 m= (10 bbl/0.044 = 227 ft)

95

GRADIENT OF INFLUXInflux Density (kg/l) =


96/217

430 psi 715psi

SIDPP30 bar

SICP50 bar

Height of influx =160 m (525 ft)

Mud Weight = 1,44 kg/l (12 ppg)

Well Data:

Gradient of Influx (bar/m) == 0.166 kg/l x 0.0982 = 0.01628 bar/m

0981,0x)m(TVDInflux)bar (SIDPP)bar (SICP(

)l/kg(WeightMud

l/kg166.00981.0*160

)3050(44.1

Field Unit : Influx Density (ppg) =

Gradient of Influx (bar/m) == 1.56 ppg x 0.052 = 0.0811 psi/ft

052,0x)ft(TVDInflux))psi(SIDPP)psi(SICP(

)ppg(WeightMud

ppg56.1052.0*525

)430715(12

96

Influx Density


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Influx Density

Densities:Gas 0,18 - 0,36 kg/liter (1,5 - 3 ppg)Oil 0,6 - 0,84 kg/liter (5 - 7 ppg)Salt water 1,03 -1,20 kg/liter (8,6 -10 ppg)

Gradients:Gas: 0,02 - 0,04 bar/m ( 0.078 0.156 psi/ft)Oil: 0,06 - 0,08 bar/m ( 0.260 0.364 psi/ft) Salt Water: 0,10 - 0,12 bar/m (0.482 0.520 psi/ft)

Bes t to hand le al l k icks as gas k i ck un t i l show sotherwise .

97


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SHALLOW GAS CONSIDERATIONS


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SUGGESTED DIVERTING PROCEDURE:

Space out so that the lower safety valve is above the drillfloor.

With diverter line open , close shaker valve and diverterpacker.

Maintain maximum pump rate and pump kill mud ifavailable.

Shut down all nonessential equipment. Monitor soil around the rig floor for evidence of gas

breaking out around conductor. If mud reserves run out then continue pumping with any

fluid. While drilling top hole a float valve should be run .

99


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GAS BEHAVIOUR

100


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Gas Migration


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Gas Migration

Gas migration in an open well: Bottom Hole Pressure DECREASES Gas Bubble Pressure DECREASES Gas Bubble Volume INCREASES

Gas migration in a closed in well . All Pressures in the Wellbore INCREASE

Gas Bubble Pressure STAYS THE SAME Gas Bubble Volume STAYS THE SAME

102

Understanding Gas Behaviour


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Understanding Gas Behaviour

You should be familiar with Boyles Gas Law .

(P1 x V1 ) = (P2 x V2)

The Ps stand for pressure and the Vs stand for volume. The P1 and V1 apply before any change has taken place.

The P2 , V2 apply after any change.

103

Uncontrolled Expansion


104/217

The gas bubble gets bigger,

It pushes more and more fluid out of the hole, The hydrostatic pressure of this mud is also lost,

The result is that BHP will drop,

This cause an under-balance and the influxentering the hole.

A1 bbls

B?? bbls

C353 bbls

Bottomhole Pressure (BHP)353 bar

(5,200 PSI)

(P1 x V1 ) = (P2 x V2)

(353 bar x 1 bbl) = (1 bar x V2) V2 = 353 bbl

104

Gas Migration in Closed Well


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Gas Bubble is at the Bottom Hol e

800 liter (5 bbl) influx at Bottom Hole At the gas bubble the pressure is equal

to Hydrostatic Pressure (HP)

Mud Weight 1,2 kg/liter (10 ppg)

TVD = 3000 m (10000 psi)

HP = 0,0981 * 1,2 * 3000 = 353 bar(HP = 0,052 * 10 * 10000 = 5200 psi)

GAS 353 bar

(5,200 PSI)

800 liter(5 bbls)

Casing Shoe

1,2 kg/liter(10 ppg)

Mud

Choke

3000 m (10,000 feet)105

Gas Migration in Closed WellGas Bubble at the Surface


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Gas Bubble at the Surface

Choke (closed)

BOP (Closed)

353 bar (5,200 PSI)Gas pressure

+353 bar (5,200 PSI)

Hydrostatic Pressure

The gas migrate to surface

(p1*V1 =p2*V2)

Gas volume unchanged in closed system =

= 800 liter, (5 bbl)

Gas Volume at Bottom = Gas Volume atSurface

Gas Press. at Bottom = Gas Press. at Surface

Gas Press. at Surface = 353 bar (5200 psi)

BHP =

= Gas Press. at Surface + Hydrostatic Press.

= 353 bar (5200 psi) + 353 bar (5200 psi) =

= 706 bar (10400 psi) BHP=706 bar(10400 psi) 106

Maximum Surface Pressure


107/217

When a gas kick is circulated to the surface, its volume will expand .

The gas will achieve its maximum volume at the surface .

Annular surface pressure depends on:

Greater underbalance

Larger vol ume of the kick Higher surface pressure

Lower density of the influx Annulus becomes smaller

Hole depth increases Pressures increase

Mud density increases

Circulating the kick with kill mud Lower surface pressures

Gas percolation in closed well Surface pressures close to FP

107

Gas Migration Rate


108/217

g

Gas Migration Rate (m/h) =Example:

SICP Increase in 1 hour = 20 bar (286 psi);Mud Weight = 1.44 kg/l (12 ppg)

Gas Migration Rate =

10.2l)eight kg/ud

bar/h)ICPnhange

h410. 21.44 kg/l)

bar/h)0

Field u ni t :

Gas Migration Rate = 0.052*g)Weight(ppMud(psi/h)SICPinChange

ht580.0522 ppg)

psi/h)86

108

Gas Migration Rate


109/217

Gas migration rate:

In water based mud: Average 0,5-5 m/min In salt water: 10-20 m/min in salt waterIn Oil based mud:

Methane dissolves in oil base mud 20-40 m /m Difficult the kick detection Large gas influx lower change in pit volume,

lower SICP.

When the influx is circulated up the wellbore No likely expansion , Rapid expansion at bubble point near to surface .

109


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CIRCULATION and WELL CONTROL

110

Circulation and Well Control


111/217

Circulation and Well Control

Goals: Circulate kick out,

Pump kill mud in the hole,

Maintain constant BHP equal or slightly higher thanFormation Pressure,

Accurate SPM control,

Kill Sheet Calculation ,

111

Kill Rate KRReduced circulation


112/217

Reduced circulation Advantages :

Lower annulus friction pressure, Reduced risk of pump breakdown,

More time to react problems,

Reduced gas rates through mud-gas separator, Keeping within the capability of barite mixing system

Allows choke to work:

Proper orifice range,

Less pressure fluctuation in response to a change inchoke setting.

Normally 1/3 to 1/2 of normal drilling circulation rate112

Kill Rate Pressure (KRP)


113/217

113

KRP must be measured for both pumps and recorded indaily report and kill sheet:

Every tour by each driller ( at least in every shift )

When the pumps are repaired or liners changed

If mud properties are changed

Every 100 m (300 feet) of hole drilled

When the BHA changed

When bit nozzles are changed

Must be verified before well killing

Kill Rate Pressure (KRP) Calculation


114/217


New Pump Pressure with New Pump Rate approximate (bar):

Example: Old Pump Pressure: 200 bar (2862 psi)Old Pump Rate: 90 strks/minNew Pump Rate: 40 strks/min

2

)(strks/minRatePumpOld)(strks/minRatePumpNew

x)Press.(bar PumpOld(bar)Press.PumpNew

bar 5.39)(strks/min90

in)40(strks/mx200(bar)PressurePumpNew

2

psi565)(strks/min90

in)40(strks/mx2862(psi)PressurePumpNew

2

Field Unit:

114



115/217


New Pump Pressure with New Mud weight (bar):

Example:

Old Pump Pressure: 100 bar (1430 psi)New Mud Weight: 1,44 kg/liter (12 ppg)Old Mud Weight: 1,12 kg/liter (10.4 ppg)

(kg/l)WeightMudOld(kg/l)WeightMudNew

xar)Pressure(bPumpOld(bar)PressurePumpNew

ar b115(kg/l)1.25(kg/l)1.44

x(bar)100 PressurempNew

Field unit:

sip1650(ppg)10.4

(ppg)12x(psi)1430 PressurePumpNew

115

Initial Circulation Pressure (ICP)


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ICP Calculation:ICP = Kill Pump Rate Pressure (bar) + SIDPP (bar)

Example:Kill Pump Rate Pressure (KRP): 52 bar (750 psi)Shut-in Drill Pipe Pressures (SIDPP): 14 bar (200 psi)

ICP (bar) = 52 + 14 = 66 ba r

Field Unit: ICP = 750 + 200 = 950 psi

116

Final Circulation Pressure (FCP)


117/217

OMW increase to KMW Circulation pressure decrease

Final Circulation Pressure, FCP (bar) =

= Kill Pump Rate Pressure (bar) x

Example: Kill Pump Rate Pressure: 100 bar (1430 psi)Kill Mud Weight: 1,44 kg/lit er (12 ppg)Original Mud Weight: 1,12 kg/liter (10.4 ppg)

)l/kg(WeightMudOriginal)l/kg(WeightMudNew

r ba115(kg/l)1.25(kg/l)1.44

x(bar)100 (FCP)PressurenCirculatioinal

psi1650(ppg)10.4

(ppg)12x(psi)(1430 (FCP)PressurenCirculatioFinal

Field unit:

117

Hole Volume CalculationP S k d Ti


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Pump Strokes and Time

Surface to Bit (Drill String) Drill Pipe (DP)

Heawy Wall Drill Pipe (HWDP)

Drill Collar (DC) Bit to Surface (Total Annulus Volume)

Bit to Casing Shoe (Open Hole)

DC OH DP/HWDP OH

Casing Shoe to Surface (DP Casing)

118


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WELL CONTROL METHODS

119

Maintenance of Primary Well Controlhil D illi d Ci l ti


120/217

while Drilling and Circulating

1. Ensure Mud weight correct.

2. Ensure pit level recorders are operational.

3. Any change inform Driller.

4. When a drilling break, take flow check .

5. Maintain accurate records.

120


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Secondary Well Control

121

KILL METHODS


122/217

Objectives of Well Control Methods

Circulate the kick safely out of the well

Re-establish primary well control by restoring hydrostatic balance

Avoid additional kicks Avoid excessive pressures that may fracture the weak zone andinduce an underground blowout

122

Well Control Methods


123/217

Drillers Method Wait and Weight Method

Concurrent Method

Volumetric Method Bullheading

Reverse Circulation Method

1-2 most often used.

123

Differences


124/217

At drillers method

Kick circulated with Original Mud . Kill Mud circulated in second step.

At W W method

Kick circulated with Kill Mud.

At concurrent method

Mud Weigh increased in steps by step . New mud circulated down.

Circulating pressures recalculated.

124

Secondary Well ControlWell Control Methods String on Bottom


125/217

Well Control Methods String on Bottom

WAIT & WEIGHT - Applied universally as first choice

DRILLERS - Applied in highly deviated / horizontal wells & by mostoperators in most applications worldwide . SIMPLE!

CONCURRENT - Applied by some operators who still prefer toDrillers method. Pumping weighted mud can start any time.

BULLHEAD - Applied when conditions dictate (fractured formations)

REVERSE - Applied as primary method in workover operation.

VOLUMETRIC When string is plugged or circulation not possible

125

Secondary Well ControlThree Rules for Well Killing


126/217

Three Rules for Well Killing

Rule 1Keep BHP Formation Pressure

Rule 2Special cases annular friction loss is considered.

Rule 3Once the kick is below the casing shoe , the MAASP the criticalfactors for well killing.Once the kick is inside the casing , the pressure rating of surfaceequipment become critical factors for well killing.

126


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Drillers Method

127

DRILLERS METHOD


128/217

DRILLERS METHOD

Viable option if barite was unavailable/limited

Mixing equipment limitations means long waiting time

Less chance of gas migration

Circulation begins right away

Weather may be a consideration

Fewer calculations at start of operation

Consideration to select the Drillers Method

128

DRILLERS METHOD


129/217

DRILLERS METHOD

Well under pressure longest with two circulation's

Under certain circumstances the highest shoe pressures

Standpipe pressure the highest for the longest time

Annular surface pressure the highest

Consideration do not select the Drillers Method

129

Drillers Method


130/217

Method

130

Drillers MethodProcedure


131/217

Procedure

Kick occurs, shut-in the well by the operator's/contractor's procedure

Record SIDPP, SICP, Pit gain

Complete the Kill Sheet

Some information are pre-recorded

Start circulation

Open choke start up pump to kill rate

SICP hold constant by choke (BHP is constant)

131



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Pump at constant Kill Rate

ICP remain constant by choke Circulate kick out

ICP = KRP + SIDPP = Constant

If kick pumped out

Stop the pump, close the choke

Casing Pressure = SIDPP

Kill Mud Circulation

Open choke, bring pump to Kill Pump Rate

Casing pressure keep constant

132



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While Kill Mud fill-up the drill string

ICP decrease to FCP

Kill Mud at the bit


Observe casing and drill pipe pressureCasing Pressure = SIDPP

SIDPP = 0

Start the pump


Casing pressure keep constant

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Circulate until Kill Mud appears at the choke

Constant pump rate

Circulation pressure = FCP

Stop pump

close the choke keeping casing pressure constant Observe the pressures

Casing Pressure = Drill Pipe Pressure 0

Bleed off the trapped pressure through choke

Flow check through choke

If the well flows a dditional circulation.

134

Drillers Method

P(bar)

ICP= 71


135/217

SP= 10+

KPP= 28

+ FCP= 31 SIDPP= 33

Drillers MethodP(bar)

MAASP 3 = 134 MAASP 2 = 73 LOT

LOT = 100

Pa max = 92SIDPP= 33

SICP= 45

2033 870 1586 3619

4008

4877 Ote`avanje 6463

Pump (strks/m,in)

135

Drillers Method


136/217

Advantages

Simple calculations E asy to learn

Circulation start immediately

Limited problems

Stuck pipe

Plugging

Migration

Disadvantages

High surface casing pressure

High casing shoe pressure mud loss

Longer time of circulation.

136


137/217

Wait & Weight Method

137

WAIT & WEIGHT METHOD


138/217

WAIT & WEIGHT METHOD

One circulation:

lesss time on the choke and equipment is under pressure

In some circumstances lower casing shoe pressures

With a long open hole section less chance of lost circulation

Reduces pressures on standpipe side quickly

Consideration to select the W&W Method

138

WAIT AND WEIGHT METHOD


139/217

WAIT AND WEIGHT METHOD

Gas migration may become a problem while waiting on kill mud

Hole problems due to cuttings settling while waiting on kill mud

Cooling down period could induce hydrate formation.

Consideration do not select the W&W Method

139



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140

Wait & Weight Method Procedure


141/217

Procedure

Kick occurs, shut-in the well by the operator's/contractor's procedure Record SIDPP, SICP, Pit gain

Complete the Kill Sheet

Some information are pre-recorded Start Kill Mud Circulation


SICP hold constant by choke (BHP is constant).

141

Wait & Weight Method Procedure


142/217

Procedure

While Kill Mud fill - up the drill string

Constant Kill Rate

Follow the Drill Pipe Pressure Plot

ICP decrease to FCP

Kill Mud at the bit


Observe casing and drill pipe pressure

Drill Pipe Pressure = 0

Casing Pressure SICP

142

Wait & Weight MethodProcedure


143/217

Circulate until Kill Mud appears at the choke

Constant pump rate

Circulation pressure = FCP

Stop pump

close the choke keeping casing pressure constant

Observe the pressures

Casing Pressure = Drill Pipe Pressure 0

Bleed off the trapped pressure through choke

Flow check through choke

If the well flows a dditional circulation.143

Secondary Well ControlWait & Weight & Drillers Methods


144/217

Phase 1

P DP

P ST

P C1

P C2

P C2

Standpipe Pressure for Drillers Method

Standpipe Pressurefor W&W Method

W&W: Well killed atend of Phase I inside thedrill string

SIDPP

.. due to change in mud

due to constant mud

144


Di d


145/217

Disadvantages:

Circulation can not start immediately. Long time to Wait & Weight- up the mud. Problems occures: Gas migration, Stuck pipe,

Downhole plugging.

Advantages: Kill Mud is present at the bottom before kick removed

through the choke. Lower surface casing pressure.

Lower casing shoe pressure at long openholesection (Volume surface to bit Openhole Volume).

Shorter time of circulation.

145


146/217

Volumetric Method

146

VOLUMETRIC METHOD


147/217

Volumetric Method is applied to a well if the hole conditionis having one of the followings:1. Circulation is not possible

String is out of the hole, String is plugged, Pump is shut-down or unavailable and there is a float valve in the

string.2. Circulation is not recommended

Bit is off bottom above the TVD; Stripping to bottom is not possible,

3. Bullheading is not possible

147

VOLUMETRIC METHOD APPLICATION


148/217

The Volumetric Method Application has the same concept ofConstant Bottom Hole Pressure Technique as the other wellcontrol methods have.

Choke manifold is connected to the Trip Tank.

Some pre-calculated amount of drilling mud is bled off from themanual choke for a selected pressure increase (working pressure)at every cycle.

BHP maintains constant because

BHP = SICP + HPmud

148



149/217

Volumetric Method Application has the same concept of ConstantBottom Hole Pressure Technique as the other well control methodshave.

Choke manifold is connected to the Trip Tank.

Some pre-calculated amount of drilling mud is bled off from themanual choke for a selected pressure increase (working pressure)at every cycle.

149


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150



151/217

The following straightforward formula is used for the Volumetric

Well Control:Volume To Be Bled ( liter) =

Pressure Increase (bar) x Hole or Annular Capacity (liter/m)

Mud Gradient (bar/m)=

Volume To Be Bled:(liter or bbl)

Mud volume to be bled from the manual chokeat every cycle.

Pressure Increase:(bar or psi)

Selected working pressure on the casing gaugefor every cycle.

Hole or Annular Capacity:(liter/m or bbl/ft)

Capacity of the place where gas influx islocated in the hole.

Mud Gradient:(bar/m or psi/ft)

Drilling mud gradient in use.

151

VOLUMETRIC METHODKILL EXERCISE


152/217

WELL CONFIGURATION:

After pulling out of the hole a kick is taken and the well is shut-in byblind rams. Formation influx is gas The kick has occurred because of the Trip Margin . The bullheading method was not possible due to the week formation at

the casing shoe. It is decided to use the volumetric method to control bottom hole

pressure as the influx migrates.

This will be done by using the followings:Safety margin 200 psiWorking pressure 100 psi

152

VOLUMETRIC METHOD KILL EXERCISEWELL DATA


153/217

MD/TVD: 5600 ft

9-5/8 casing shoe : 3950 ft

Open hole capacity: 0.0702 bbl/ft (hole capacity is constant)

Casing capacity: 0.0702 bbl/ft (hole capacity is constant)

Mud density in use: 12.6 ppg (0.655 psi/ft)Gas hydrostatic pressure: 25 psi (sabit)

Influx volume 12.6 bbl

Formation pressure (Pf) 3670 psi

SIDPP 0 psi (drill string is out of the hole)

SICP 100 psi

153

T100BOP

CLOSED

SICP= 100 psi VOLUMETRIC METHODKILL EXERCISE

MANUALCHOKE


154/217

T100CLOSED

SICP= 100 psi (is stabilized casing pressure)BHP = Formation Pressure (3670 psi)

TRIP TANK

CHOKE

CHOKE LINE

Mud Density = 12.6 ppgMud Gradient = 0.655 psi/ft

P (psi) x Ca (bbl/ft) V (bbl)

MG (psi/ft)=

.

V (bbl): Mud volume to be bled from the manual choke at every cycle.P (psi): Selected working pressure on the casing gauge for every cycleCa (bbl/ft): Capacity of the place where gas influx is located in the hole.

MG (psi/ft): Drilling mud gradient in use.

154

T100BOP

Closed

SICP= 100 psi VOLUMETRIC METHODKILL EXERCISE

MANUALCHOKE


155/217

T100Closed

SICP= 100 psiBHP = Formation Pressure (3670 psi)

TRIP TANK

CHOKE

CHOKE LINE


At the given example :

Safety Margin = 200 psi

Working Pressure (P) = 100 psi is selected

100 (psi) x 0.0702 (bbl/ft)V (bbl) 0.655 (psi/ft)=

= 10.7 bbls = 11 bbls !!

155

T400BOP

CLOSED

CP= 400 psi VOLUMETRIC METHODKILL EXERCISE

MANUALCHOKE


156/217

T400CLOSED

CP = 400 psi,BHP = Formation Pressure + 300 psi (3970 psi)

TRIP TANK

CHOKE LINE


Casing Pressure = 400 psi,

BHP = Formation Pressure + 300 psi.

Safety Margin = 200 psiWorking Pressure (P) = 100 psi

156

T400

CP= 400 psi

MANUALCHOKE

VOLUMETRIC METHODKILL EXERCISE

BOPCLOSED


157/217

T400

CP= 400 psiBHP = Formation Pressure + 200 psi (3870 psi)

TRIP TANK

CHOKE LINE


Casing Pressure = 400 psi,BHP = Formation Pressure + 300 psi.


11 bbl

To maintain the BHP 200 psi higher than Formation Pressure, Casing Pressure is held constant at 400 psi by Manual Choke

until 11 bbls mud is bled off into the Trip Tank.

157

T500

CP = 500 psi VOLUMETRIC METHODKILL EXERCISEBOP

CLOSEDMANUALCHOKE


158/217

T

CP= 500 psi,BHP = Formation Pressure + 300 psi (3970 psi)

TRIP TANK

CHOKE LINE


Casing Pressure = 500 psi,

BHP = Formation Pressure + 300 psi.


11 bbl

158

T500


CLOSEDMANUALCHOKE


159/217

T500


TRIP TANK

CHOKE LINE


Casing Pressure = 500 psi,BHP = Formation Pressure + 300 psi olur.


22 bbl

To maintain the BHP 200 psi higher than FormationPressure,

Casing Pressure is held constant at 500 psi by ManualChoke until 11 bbls mud is bled off into the Trip Tank.

159

T600


CLOSEDMANUALCHOKE


160/217

T600


TRIP TANK

CHOKE LINE


Casing Pressure = 600 psi,BHP = Formation Pressure + 300 psi.22 bbl


160

T600


CLOSEDMANUALCHOKE


161/217

T

TRIP TANK

CHOKE LINE




CP= 600 psiBHP = Formastion Pressure + 200 psi (3870 psi)

To maintain the BHP 200 psi higher than Formation Pressure, Casing Pressure is held constant at 600 psi by Choke until

11 bbls mud is bled off into the Trip Tank.

161

T700


CLOSEDMANUALCHOKE


162/217

T


TRIP TANK

CHOKE LINE




162

T700


CLOSEDMANUALCHOKE


163/217

T

TRIP TANK

CHOKE LINE




CP= 700 psiBHP = Formastion Pressure + 200 psi (3870 psi)

To maintain the BHP 200 psi higher than Formation Pressure, Casing Pressure is held constant at 700 psi by Choke until

11 bbls mud is bled off into the Trip Tank.

163

1000

VOLUMETRIC METHOD KILL EXERCISE


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900

800

700

600

500

400

300

200100

997766554433114433221100

22 88

C a s

i n g

P r e s s u r e

( p s i )

Bled Volume (bbl)

Start the LUBRICATE & BLEEDTECHNIQUE

Gas at surfaceWhen gas reaches the surface casingPressure does not increase any more.

164


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LUBRICATE & BLEED TECHNIQUE

165

LUBRICATE & BLEED TECHNIQUE


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Lubricate and Bleed Technique is the next stage of VolumetricMethod.

During the application of this procedure, Constant Bottom HolePressure Technique is applied to the well as used in the othermethods.

First mud is pumped through the kill line into the well and then gas isbled off from the manual choke to decrease the well head pressure.

166



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The formula is used for the Volumetric Well Control:

Volume To Be Pumped ( liter) =

Pressure Decrease (bar) x Well or Annular Capacity (liter/m)

Mud Gradient (bar/m)=

Volume To Be Pumped:(liter or bbl)

Mud volume to be pumped pumped for theselected pressure decrease.

Pressure Decrease:(bar or psi)

Selected pressure decrease on the casingpressure.

Well or Annular Capacity:(liter/m or bbl/ft)

Well or annulus capacity where gas located inbelow the BOP.

Mud Gradient:(bar/m or psi/ft)

Gradient of the mud to be pumped into the well.

167

T700BOP

CLOSED

CP = 700 psi

MANUALCHOKE

MUD INLET

LUBRICATE & BLEED TECHNIQUEKILL EXERCISE


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T


TRIP TANK

CHOKE LINE


Surface equipment are lined up.


GAS OUTLETKILL LINE

MUD INLET

168

T750BOP

CLOSED

CP = 750 psi

MANUALCHOKEMUD INLET



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T


TRIP TANK

CHOKE LINE




GAS OUTLETKILL LINE

11 bbls kill mud is pumped into the well Then 10 to 15 minutes is waited for mud-gas separation. CP increases because of the gas compression. In this example, CP = 700+50 = 750 psi.

169

T600BOP

CLOSED

CP = 600 psi




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T


TRIP TANK

CHOKE LINE




GAS OUTLET

KILL LINE

CP is decreased to 600 psi by bleeding gas fromthe manual choke.

170

T675BOP

CLOSED

CP = 675 psi




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T


TRIP TANK

CHOKE LINE




GAS OUTLETKILL LINE

11 bbls kill mud is pumped into the well Then 10 to 15 minutes is waited for mud-gas separation. CP increases because of the gas compaction. In this example, CP = 600+75 = 675 psi.

171

T500BOP

CLOSED

CP = 500 psi

MANUALCHOKE

GAS OUTLETMUD INLET



172/217


TRIP TANK

CHOKE LINE




GAS OUTLET

KILL LINE

CP is decreased to 500 psi by bleeding gas fromthe manual choke.

172

T0

CP = 0 psi

Surface equipment are lined up as

LUBRICATE & BLEED TECHNIQUEKILL EXERCISEBOP

CLOSEDMUD INLET

MANUALCHOKE


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CP= 0 psiBHP = Formation Pressure

Surface equipment are lined up asshown in the figure at left.



KILL LINECHOKE LINE

GAS OUTLET

TRIPTANK

Lubricate & Bleed Technique is applied tothe well at every cycle by pumping 11 bblsmud into the well and bleeding gas for theequivalent 100 psi pressure decrease untilthe CP = 0 psi.

Mud volume to be pumped into the hole and the propercasing pressure decrease will may be lowered at thefollowing cycles. For example: 5.5 bbls mud is pumped

and then CP is decreased by 50 psi.

173

T0BOP

CLOSED

CP = 675 psi




174/217


TRIP TANK

CHOKE LINE




GAS OUTLETKILL LINE

11 bbls kill mud is pumped into the well Then 10 to 15 minutes is waited for mud-gas separation. CP increases because of the gas compaction. In this example, CP = 600+75 = 675 psi.

174

1000

VOLUMETRIC METHOD and BLEED & LUBRICATE TECHNIQUE


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900

800

700

600

500

400

300

200100

997766554433114433221100

VOLUMETRICMETHOD

LUBRICATE & BLEEDTECHNIQUE

22

88

C a s

i n g P

r e s s u r e

( p s i )

Bled Volume (bbl) Pumped Volume (bbl)

Gas at surface

Gas is Out OfThe Well

175


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Concurrent Method

176

Procedure for Concurrent method

Well is closed in


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Well is closed-in,Basic information recordedCalculate kill sheet Calculate ICP, FCP, MW, strokes

Start the pump, bring up to KRSICP constantWhen pump is at KR Control ICP

When circulatingMud mixing personnel call up MW each time when it is readyWhen MW is pumping from surface to bit the choke operatoradjust the pressure by the graph.

Continue circulating untilKMW reaches to chokeWell is killed Flow check

177

Weight-up considerations Using Driller s, W&W, concurrent method

Th d b i h d ( i ) KWM


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The mud must be weighted up (continue) to KWM.

Barite is the best weighting material Important to know required number of sacks

2W35

1W2W1470=SX

W1 - initial MW - ppg W 2 - desired MW - ppg

SX - sacks of barite to 100 bbl of mud

Vi volume increase bbl N number of sacks

9,14 NVi

178

Example

2 2 2


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W1 = 12,2 ppg W 2 = 12,7 ppg

SX = 33 sacks to 100 bbl mud 100 lb/sack

Vmud - m 3 KWM, OMW - kg/liter

By the practice

Barite (t) =KWM2,4

OMWKWMV2,4

mud 2,4

BV ti

179

CONCURRENT METHOD


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Most complicated

More record keeping

Higher casing pressure than W&W method (gas kick)

Complicated mud mixing - weighted up in a series steps

Weighting time - circulation time need But max CSG pressure less than at Driller s method.

180


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LOW CHOKE-PRESSURE METHOD

181



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SICP rises while circulating

But BHP is constant

Decrease SICP is safer?

Reduce BHP - new kick

Some cases low choke method is usable

Employed areas of underbalanced drilling

182



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Drill tight low permeability formations Operator must be familiar Crew continue drilling

Underbalanced Keep high ROP Avoid damaging of fractured formations

Influx must be low Operator must have a good practice

Know the characteristics

SICP must be lower than limitations

183


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Unusual Well Control Operation

184

Annulus Pressure with Influx on Bottom


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holeof bottomonInfluxof Volume1Vholeof bottomatPressure1P

P o

H i n f l u x

influx

mudluxluxOtop inf inf

:Influxof topatPressure

luxHWellDmudtopPChokeP inf

:Chokeat Pressure

luxHShoeDWellDmudtopPShoeP inf

:Shoeat Pressure

185

Bottom of Influx at a known depth


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P o

H i n f l u

x

P Bottom

P Top

X

*luxinf WellmudtopChokeHXDPP

mud

XO

P BottomP2P

2

11

112

22112V

PP

VZTPZTP

V

AnnulusCapluxH 2

V

*inf

luxlux

HbottomPtopP inf *inf

Shoeluxinf WellmudtopShoe DHXDPP *

186


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Reverse Circulation

188

Reverse Circulation

R l d i D illi O ti b id d


188/217

Rarely used in Drilling Operations may be considered anoption in case of a weak shoe.

Common practise when killing a production well for aworkover - in cased hole.

In a reverse circulation kill, the fluid is pumped down thecompletion annulus and returns are taken up thecompletion .

The control of the operation is again by adjustment of thechoke opening on the line from the completion/tree.

It has the great advantage of filling the tubing and annuluswith kill fluid in one operation.

As the kill fluid enters the completion, there is a probabilitythat gas will be encouraged to enter the kill fluid as it ispumped up the completion . 189

Reverse Circulation

Tubingpressure

Packer fluid is not same then the killing fluid.

Tubing draw-down pressure is controlled by the choke .


189/217

Annuluspressure

Start the circulation

Tubing

strks

Pressure (bar)

0

20

40

60

80

100

120

140

160

180

0 500 800 1000 1500 2000 2500 3000 3500 4000 4500 5000

Tubing pressure draw-down chart

Tubing

Gas circulate out through Tubing

Packer fluid circulte through Tubing

Kill Fluid fill up the tubing

SITP

Tubing and annulus volume (strks)190


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Blocked Nozzles

191

Post Kick Calculations Blocked Nozzles


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Sudden rise on PC1 with no effect on Pchoke DP pressure loss will increase without effecting BHP Most likely around time 2 mud reaches bit if poor mixing

occursProcedure:

Shut In well and check all is OK, record P DP* Start to pump holding Pchoke constant. Drillers Method

Continue holding PST* constant Wait & Weight Method

Determine P C* (=PST* - PDP*) Determine the additional pressure due to blocked nozzles

(PC*-PC) Replot kill graph using this additional back pressure.

192

Secondary Well Control

Dealing with Blocked Nozzles (W&W)P *


192/217

Phase 1

PDP*

PDP

PST*

PST

PC*

PC

PC*-PCPC1

PC2

PC2*

PC*-PC

193


193/217

Losses above a Pressure Zone

194

Kicks & Losses - Losses above a Pressure Zone

G Ki k Sh B kd I l Bl


194/217

Gas Kick Shoe Breakdown Internal Blowout

Initial P BH = TVDH x mud PBH after kick = P O = Initial P BH + PDP Initial P Shoe = TVDCsg x mud

PShoe after kick = Initial P Shoe + PAnn Initial Influx Height = (P Ann PDP) (mud infl) As shoe breaks down, crossflow from reservoir to

loss zone will occur. At high rates this will cause

drawdown on the reservoir, reducing near well-bore P O ( PBH Flowing ).

0

195

Kicks & Losses - Losses above a Pressure ZonePAnnP DP


195/217

mud gas

P FS

P O

196

Losses above a Pressure zone Development of an Internal BlowoutP

AnnP DP


196/217

0

mud gas

P FOP FP P UF

Drawdown

Q increasing

197

Losses above a Pressure zone Annulus Siphoned Empty of Mud


197/217

0

P FOP FP

P UF

Q increasing

Q increasing

Drawdown

Siphoning out Siphoning out

198

Losses above a Pressure zone - Resolution

Final situation can cause high casing pressures at surface


198/217

Pump water or low density mud down the annulus mud < fracture propagation pressure Keeps gas out of csg, reduces surface pressures

Keep drillstring full if possible

Increases BPH and reduced production rate Prevents nozzles plugging Prevents ingress of gas into drillstring

Attempt to cure losses by pumping LCM Beware proppant effect in fractures Consider pumping gunk (diesel / barites) down annulus &

water down string199


If unable to cure losses: Prepare heavy mud with density:


199/217

Prepare heavy mud with density:

CSGH

losses.aboveCSGO*M DD

DP

When ready, pump 2 x OH Annulus volume down DP Displace to bit with 1 mud

This should reduce the influx rate and,assuming only one loss zone, should killwell.

200


200/217

Losses above a Pressure zone Resolution

201


If losses are cured


201/217

Indicated by increase in P DP and P Ann Prepare kill mud based on estimated P O Monitor P DP as gas migrates into the csg from OH annulus

Keep P BH constant by keeping P DP constant Consider displacing gas using Drillers method

Displace well to new mud gradient using Weight & waitmethod.

Will be necessary to isolate loss zone (and much of OH section)behind casing before drilling ahead.

202

Kicks & Losses - Losses below a Pressure zone

If loss zone penetrated below a pressure zone. x


202/217

DGas

DH

flowstart towillthen wellP

LossesafterSandGasatPressure

SandGasat pressuremudInitial

can takeformationloss that pressureMaxInitial

Gas Mud Gas

Mud Gas

Mud Gas

Mud H

Mud H BH

X D If

X D Mud

D

X D D P

If no action is taken. Levels in DP and annulus will drop, If overbalance is lost gas influx will occur,

Gas will percolate up and down, As gas rises in annulus, mud will be displaced until

flow is seen at surface, Well would then be closed in.

203

Losses below a Pressure zone Development of Internal Blowout

When well is shut in Gas migration up the annulus if not allowed to


203/217

Gas migration up the annulus if not allowed toexpand will increase P BH leading to morelosses.

Gas will flip with mud causing casing to befilled with gas.

Eventually whole well may become displacedto gas.

Surface pressure will rise to close to theFlowing P O of the gas zone.

An internal blowout will occur with the lowerzone becoming supercharged.

DGas

DH204

Losses below a Pressure zoneImmediate Response

On observing losses:


204/217

1. Keep annulus full if possible Pump mud and then water Will reduce drawdown on producing interval

mWGZwWGZ

wmWHmPZ

CSGxDPW

HDHPdrawdownZoneGasHDPPressurePorezoneLoss

CapV

H

:lossesobservingafterwaterof bblVwithfilledisholeIf

205

Losses below a Pressure zone Resolution

1. Attempt to cure losses down the drillstring with LCM Use circulating sub if installed


205/217

g

Beware plugging bit nozzles2. Minimum nozzle size when pumping LCM: 14/32

If LCM unsuccessful consider: Diesel / Bentonite gunk pill Thixomix (flash setting) cement Cement / LCM combinations

3. After curing losses:1. Set cement plug across / above loss zone2. Displace well back to 1 mud3. Set casing / drilling liner to isolate producing zone4. Drill ahead.

206


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Horizontal Well Control

207

Horizontal Holes

M h i l ll d ill d f d l h


207/217

Most horizontal wells are drilled for development as ratherthan for exploration reasons.

Well control in these situations might not be regarded ascritical as:

Reservoir behaviour / pressure is well known Mud weight generally selected to provide overbalance and

maintain well-bore stability - an under-balance is unlikely

Casing is normally set directly above the producingformation

However, horizontal wells have a great capacity for flow.

208

Horizontal Drilling Well ControlCauses of Kicks

Insufficient mud weight:


208/217

Insufficient mud weight:-

Drilling across a fault into a high pressure formation

Mud weight reduced due to gas cutting, water cutting

Swabbing:-

Documents

Well Control Slideshow 2014_15.pdf