Well Control Slideshow 2014_15.pdf

WELL CONTROL LAB

Course Description

• Causes of kicks, warning signs of kicks,

shutting-in procedures, the risk of shallow gas,

stripping operation, pressure balance in the

hole, behavior of gas in the well, well control

methods, well control equipment, BOP stack

arrangements, manifolds and valves systems,

other devices, the functions and capacity of

the accumulator unit, pressure testing of well

control equipment, regulations and standards.

Assessment

Students will be assessed with using the

following elements.

• Attendance:

5 %

• Homework

10 %

• Short quizzes

10 %

• Midterm exam

40 %

• Final exam

35 %

• Total

100%

Grading

Literature

• T. Bell, D. Eby, J. Larrison, B. Ranka: Blowout

Prevention, 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, Gulf

Publishing Company, 1994, ISBN 0-88415-260-X.

Estimated Costs of Blowouts

Location and Event Year Cost M $

North Sea, Ekofisk Platform, Blowout 1976 56 West Africa, Onshore Blowout 1978 90 North America, H2S Blowout 1982 50 North America, Underground Event, Jack-Up 1985 124 S. America, Platform Blowout 1988 530 North Sea, Platform Explosion and Fire 1988 1360 Norvegian North Sea, Underground Blowout 1989 284 Kuwait Oil Co., Al-Awda Project, Kuwait 1991 5400

Pusztaszőlős 34 2000 38

PRESSURE CONCEPTS

Pressure Fundamentals

The U-tube

One inside the pipe & one in the annulus

These two columns of fluid act to form a U-tube.

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

Hydrostatic Pressure

Measured Depth = MD

True Vertical Depth = TVD

Static pressure of a liquid increases with density and

depth TVD

Hp =



g



TVD

(kg/liter*0,0981 *m)

=

bar

HP = 0,052



MW



TVD

(lb/ft * ft)

=

psi

Mud gradient (MG), pressure gradient:

grad Hp = p/TVD

MG = MW*0,052

(ppg*0,052) = psi/ft

Abnormal Pressure Gradients

Normal Pressure Gradients

West Texas: 0.433 psi/ft - 8.33 ppg – 0,0981 bar/m

Gulf Coast: 0.465 psi/ft – 9,0 ppg - 0,106 bar/m

Normal and Abnormal Pore Pressure

Dept h, f t

10,000’

_?

_?

Overpressure Due To Density Differences

Pore Pressure Development Due to

s

s

s_ob

HIGH PRESSURE

NORMAL PRESSURE

Determination of Fracture Gradient

• To avoid lost circulation

while drilling it is important

to 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

theoretical

approaches to

calculating

the fracture gradient.

• Formation fracture pressure can be

expressed:

– Fracturing Pressure, bar (psi),

Fracture Gradients Determination (Theoretical ) 1. Hubbert & Willis:

Where: F = Fracturing Gradient, psi/ft, P = Pore Pressure Gradient, psi/ft D = Depth, ft         D P 2 1 3 1 F_min         D P 1 2 1 F_max

2. Matthews & Kelly:

Where: K_i = Matrix Stress Coefficient , = Vertical Matrix Stress, psi, D = Depth, ft D P D K F  is 

s

Where: S = Overburden Stress, psi,  = Poisson’s Ratio, D = Depth, ft D P 1 * D P S F _                 

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 the

formation leaks off.

– On Wild-Cat wells at each casing shoe

– On development wells, recommended

Stable Fracture Propagation Unstable Fracture 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 Pressure

LOP= Leak-Off Pressure FPP= Fracture Propagation Press. _{ISIP= Instantaneous Shut-In Press.} VOLUME P RE S S UR E TIME

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,

Leak-off Test Procedure

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

2) Circulate mud until uniform

3) Pull bit inside shoe

4) Line up on high pressure low volume pump.

5) Close the BOP.

Leak-off Test Procedure

• 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 Accurate

Leak Off Test Calculations

Hydrostatic Pressure of Test Mud to the Shoe:

1.26 x 0.0981 x 1675 = 207 bar

10.5 x .052 x 5495 = 3000 psi

Fracture Pressure = Hydrostatic Pressure + LOP = Leak-off Pressure

Formation Strength - Limit Test

Test Objective:

• Confirm pressure integrity of formation to a pre-determined pressure.

Limitations:

• Limited guidance on the integrity of the casing shoe.

• Does not quantify properties

associated with fracturing stresses. • Limit test provides limited

information!

Surface Limit Press. (LP)

Volume Pumped

(or time @ constant pump rate)

S u rfa ce P re ssu re

Leak Off Test

Low and High Permeable Formation

Leak Off Press (LOP) Vol. P res su re Initial Press Vol. P re s s u re Final Press

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 ( Hole in MudWeight (m) TVD Depth, Shoe Casing 10.2 x (bar) essure Pr LeakOff   l/ kg 95 . 1 ) l/ kg ( 44 . 1 (m) 1000 10.2 x (bar) 50    ppg 5 . 16 ) ppg ( 12 0.052 x (ft) 3048 (psi) 714 _{ }  Field Unit:

Maximum Allowable Annulus Surface Pressure

MAASP

Every time the mud weight is changed, the MAASP changes and must be re-calculated using 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 ( TVD Shoe x )] l / kg ( Hole in Weight Mud ) l / kg ( Weight Mud Allowable . Max [   bar 50 10.2 ) m ( 1000 x )] l / kg ( 44 . 1 ) l / kg ( 95 . 1 [ MAASP    Field Unit: MAASP (bar)=

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

Kill Sheet Calculation

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

Causes of Kick

Early Kick Detection

• Closed circulation system

• Flow rate IN

equal

flow rate OUT

• Constant

pit level

Exception

Kick Size

By Bill Rehm:

kick size <

3 m

(18 bbl)



no problem

,

3 m

< kick size <

6 m

(40 bbl)



good job

,

WARNING SIGNS OF KICKS

Drilling

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 the

WARNING SIGNS OF KICKS

Drilling

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 (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

WARNING SIGNS OF KICKS

Drilling

Flow check in OBM

In 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

WARNING SIGNS OF KICKS

Drilling

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

WARNING SIGNS OF KICKS

Drilling

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

WARNING SIGNS OF KICKS

Drilling

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 (

ΔP=42 bar

(624 psi)

– YES / NO

•

Penetration to formation (

L=6 m

(20 ft))

– YES

•

Time of identification (0 min)

– YES

1440

R

R

ln

μ

L

Δp

k

0,007

q

_









Darcy Law













1440

2

0.3

6

42

200

0.007

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 cuttings

Increase in drag

• if p

> p

• formation close in around DP or DC (fill-up) drag forces

(water sensitive shales)

• during the connection or tripping

WARNING SIGNS OF KICKS

Drilling

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 be

warning sign.

Increase in string weight

• Presence of kick reduces buoyant effect, sometimes can

be observed - Archimedes Law

WARNING SIGNS OF KICKS

Drilling

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 is

raised up

Trip gas -

Swabbing during the trip, there is no APL

WARNING SIGNS OF KICKS

Drilling

Gas-cut mud

• Often gas-cut mud not sign of kick

• BHP reduce not significant

• Gas expands only near the surface

Various reasons:

• Gas gets into the mud from chips

• Overpressured low permeability formation,

• Mud pressure is close to formation pressure.

WARNING SIGNS OF KICKS

Drilling

Change in shale density

• Normally increases density vs. depth

• Free water squeezed out compaction

• If density decreases below trend line contain

more water

• Overpressure suspected, at transition zone

• Difficult measurement, selecting

WARNING SIGNS OF KICKS

Drilling

Change in normalized drilling rate (d Exponent)

• Jorden and Shirley in Gulf Coast in 1966 Shell Co.

• “drilling performance date can be used to detect

the top of overpressured sediments”

• “to identify overpressures during drilling

”

WARNING SIGNS OF KICKS

Drilling

Causes of Kick

Tripping

Negative pressure waves

– reduce BHP

Increased 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 Kick

Positive pressure waves

– increase BHP

• Caused by rheology of mud

• Lost of circulation

To 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 Kick

Causes of Kick

High Volume Swabbing

Martin-Decker

VERY DANGEROUS IN TOP HOLE

• VERY RAPID GAS EXPANSION 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

Trip margin

Trip or safety margin – counterbalance swabbing effects

during 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):

TVD

0981

.

0

in

arg

TripM

MW

_increment





Example:

TM =

17 bar

(250 psi),

Causes of Kick

Tripping

Causes of Kick

Swabbing

• 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

Swabbing - Resolution

After 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

BBLS 5 10 15 10 x 90 ft stands pulled START VOLUME FINISH VOLUME 5 bbls FILL VOLUMES

TRIPPING

Causes of Kick

Tripping

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: ¼” – ½” / bbl

• if the hole not takes the correct mud volume

– Flow check

– Tripping or stripping to bottom

– Bottoms-up circulation.

Stands pulled :

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 Displacement

274 x 4.01 = 1098 litre

(900 x .00764 = 6.876 bbls)

Annular capacity inside casing with pipe still inside casing.

Casing Capacity - Metal Displacement

39.8 -4.01 = 35.79 litre/m

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

Level drop inside casing

Volume of metal removed ÷ Annular Capacity

1098 ÷ 35.79 = 30 m

LEVEL DROP WET PIPE

Volume of fluid & metal removed from the well. Length Pulled x Closed End Displacement

274 x 13.33 = 3652 litre

(900 x .0254 = 22.86 bbls)

Annular capacity inside casing with pipe still inside casing.

Casing Capacity - Closed End Displacement

39.8 – 13.33 = 26.47 litre/m

(.0758 - .0254 = .0504 bbls/ft) Level drop inside casing

Volume of fluid & metal removed ÷ Annular Capacity

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)

Pressure Drop Pulling Dry Pipe

Mud Weight = 1.44 kg/liter (12 ppg)

274 m (900 ft)

Length of pipe are pulled from the 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 . 0 01 . 4 8 . 39 01 . 4 * 0981 . 0 * 44 . 1          bar/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)

Pressure Drop Pulling Wet Pipe

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

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 . 0 33 . 13 8 . 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 from the hole with no fill-up

• 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 Kick

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)

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 have

conflicting procedures for shutting in the well.

• To provide optimum safety of personnel while

maintaining

safety of the well.

• Different well conditions

SHUT-IN PROCEDURES

Hard shut-in

Advantages

• The influx is stopped in the shortest possible time

• Minimises the volume of the influx.

• Simple and quick - there is normally no need to change

any valve alignment.

• The influx is stopped in the shortest possible time

• Lower shut-in casing pressure

SHUT-IN PROCEDURES

Hard shut-in

Disadvantages

• Pressure pulse or “water hammer” effect is produced in

the well-bore when the BOP is closed.

• To cause possible formation damage.

Hard Shut-in or Soft Shut-in?

• Depending on the

company policy.

SHUT-IN PROCEDURES

Soft shut-in

Advantage:

• Pressure pulse or “water hammer” effect is not

significant 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

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

Hard Shut-in or Soft Shut-in

“water hammer” effect

(EXAMPLE)

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

Why is the amplitude of the pressure pulse so small ?

SHUT-IN PROCEDURES

BOP Closing time (API)

All Type of BOP – 30 sec

Except:

SHUT-IN PROCEDURES

EXAMPLE

When is a Hard Shut-in Hard ?

• No reduction in Δ 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 :

– Δ P »120 psi

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

SHUT-IN PROCEDURES

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

.

Soft shut-in

Drilling

Valve arrangements:

HCR is closed



Choke open



valve open to MGS

Shut-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)

Soft Shut-in

Tripping

Valve arrangements:

HCR is closed



Choke open



valve open to MGS

Shut-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)

Hard shut-in procedures

Drilling

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

Hard shut-in procedures

Tripping

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

Collect Shut-in Data

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

Low or no SIDPP and SICP

• Pressure gauges are shut off

• No pressure → Repeat flow check

• Pressure is too low

Measurement of SIDPP and SICP with Back Pressure Valve

SIDPP

1) Start the pump with very low pump rate,

2) Continue check both Drill pipe and Casing pressures

Supervisor resposibility:

Collect Shut in data from Driller - physically check it!

• SIDPP - must 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

Supervisor :

• Instruct Driller to monitor pressure

changes on both

gauges, to avoid injection at shoe level.

• Driller must instruct the supervisor

befor the annular

pressure 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.

FORMATION PRESSURE

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) 600 psi SIDPP= 42 bar

Kill Mud Weight

Original MW = 1.44 kg/l (12 ppg)

Well Depth, TVD = 3048 m (10000 ft)

SIDPP = 42 bar (600 psi) 600 psi SIDPP 42 bar TVD = 3048 m = 10000 ft    0981 . 0 * ) m ( TVD ) bar ( SIDPP ) l / kg ( OMW ) l / kg ( MW Kill l / kg 58 . 1 0981 . 0 * 3048 42 44 . 1    Field unit:    052 . 0 * ) ft ( TVD ) psi ( SIDPP ) ppg ( OMW ) ppg ( MW Kill ppg 16 . 13 052 . 0 * 10000 600 12   

HEIGHT OF INFLUX

Determine if the influx is below or above the drill collars

Volume of Influx to reach the top of Drill Collars = 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

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

GRADIENT OF INFLUX 430 psi _715psi SIDPP 30 bar SICP 50 bar Height of influx = 160 m (525 ft)

Well Data: Influx Density (kg/l) =

Gradient of Influx (bar/m) =

= 0.166 kg/l x 0.0982 = 0.01628 bar/m    0981 , 0 x ) m ( TVD Influx ) bar ( SIDPP ) bar ( SICP ( ) l / kg ( Weight Mud l / kg 166 . 0 0981 . 0 * 160 ) 30 50 ( 44 . 1     Field Unit: Influx Density (ppg) =    052 , 0 x ) ft ( TVD Influx )) psi ( SIDPP ) psi ( SICP ( ) ppg ( Weight Mud ppg 56 . 1 052 . 0 * 525 ) 430 715 ( 12   

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)

Best to handle all kicks as gas kick until shows

otherwise.

SHALLOW GAS CONSIDERATIONS

Any kick from shallow sands can be

very hazardous

!

Some of these kicks are caused by charged formations:

– poor cement jobs,

– casing leaks,

– injection operations,

– improper abandonments,

– and previous underground blowouts.

SUGGESTED DIVERTING PROCEDURE:

• Space out

so that the lower safety valve is above the drill

floor.

• With

diverter line open

, close shaker valve and diverter

packer.

• Maintain

maximum pump rate

and pump kill mud if

available.

• 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.

Gas Migration

• Low Density of

gas starts to migrate

towards the surface.

• Not migrate at all if:

– Gas going into solution

with the drilling fluid.

– High angle of the well

: gas rises to upper side of the

wellbore.

– High viscosity

of the drilling mud - the migrating gas

trapped into mud.

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

Understanding Gas Behaviour

• You should be familiar with

Boyle’s Gas Law

.

(

P1

x

V1

)

=

(

P2

x

V2

)

• The

P’s

stand for pressure and the

V’s

stand for volume.

• The

P1

and

V1

apply

before

any change has taken place.

Uncontrolled Expansion

• 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 influx entering the hole.

A 1 bbls B ?? bbls C 353 bbls

(

P1

x

V1

)

=

(

P2

x

V2

)

(353 bar

x 1 bbl) = (1 bar x V2) →

V2 = 353 bbl

Gas Migration in Closed Well

Gas Bubble is at the Bottom Hole

• 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) 800 liter (5 bbls) Casing Shoe 1,2 kg/liter (10 ppg) Mud Choke

Gas Migration in Closed Well

Gas Bubble at the Surface

Choke (closed) BOP (Closed) 353 bar (5,200 PSI) Gas pressure

+

(p1*V1 =p2*V2)

• Gas volume unchanged in closed system =

• = 800 liter, (5 bbl)

• Gas Volume at Bottom = Gas Volume at Surface

• 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) =

Maximum Surface Pressure

• 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 volume 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

Gas Migration Rate

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 =

10.2 x l) Weight(kg/ Mud (bar/h) SICP in Change h / m 141 10.2 x 1.44(kg/l) (bar/h) 20 _ Field unit:

Gas Migration Rate = _{Mud Weight(ppg)*0.052}

(psi/h) SICP in Change h / ft 458 0.052 * 12(ppg) (psi/h) 286 _ 

Gas Migration Rate

Gas migration rate:

– In water based mud:

Average 0,5-5 m/min

– In salt water:

10-20 m/min in salt water

In Oil based mud:

• Methane dissolves

in oil base mud 20-40 m³/m³

• Difficult the kick detection

• Large gas influx

→ lower change in pit volume,

→ lower SICP.

• When the influx is circulated up the wellbore

Circulation and Well Control

Goals:

• Circulate kick out,

• Pump kill mud in the hole,

• Maintain constant BHP equal or slightly higher than

Formation Pressure,

• Accurate SPM control,

Kill Rate – KR

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 in

choke setting.

Kill Rate Pressure (KRP)

KRP

must be measured

for both pumps

and recorded in

daily 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

Kill Rate Pressure (KRP) Calculation

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

Example: Old Pump Pressure: 200 bar (2862 psi)

Old Pump Rate: 90 strks/min

New Pump Rate: 40 strks/min

2 ) (strks/min Rate Pump Old ) (strks/min Rate Pump New x ) Press.(bar Pump Old (bar) Press. Pump New        bar 5 . 39 ) (strks/min 90 in) 40(strks/m x 200(bar) Pressure Pump New 2         psi 565 in) 40(strks/m x 2862(psi) Pressure Pump New 2       Field Unit:

Kill Rate Pressure (KRP) Calculation

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) Weight Mud Old (kg/l) Weight Mud New x ar) Pressure(b Pump Old (bar) Pressure Pump New ar b 115 (kg/l) 1.25 (kg/l) 1.44 x (bar) 100 Pressure mp New         Field unit: (ppg) 12

Initial Circulation Pressure (ICP)

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 bar

Final Circulation Pressure (FCP)

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/liter (12 ppg)

Original Mud Weight: 1,12 kg/liter (10.4 ppg)

)l / kg ( Weight Mud Original )l / kg ( Weight Mud New r ba 115 (kg/l) 1.25 (kg/l) 1.44 x (bar) 100 (FCP) Pressure n Circulatio inal         F Field unit:

Hole Volume Calculation

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

Maintenance of

Primary Well Control

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.

KILL METHODS

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 and induce an underground blowout

Well Control Methods

• Drillers Method

• Wait and Weight Method

• Concurrent Method

• Volumetric Method

• Bullheading

• Reverse Circulation Method

Differences

A

• 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.

Secondary Well Control

Well Control Methods – String on Bottom

• WAIT & WEIGHT - Applied universally as first choice

• DRILLER’S - Applied in highly deviated / horizontal wells & by most operators in most applications worldwide. SIMPLE!

• CONCURRENT - Applied by some operators who still prefer to Driller’s method. Pumping weighted mud can start any time.

• BULLHEAD - Applied when conditions dictate (fractured formations)

• REVERSE - Applied as primary method in workover operation.

Secondary Well Control

Three Rules for Well Killing

• Rule 1

Keep BHP  Formation Pressure

• Rule 2

Special cases annular friction loss is considered.

• Rule 3

Once the kick is below the casing shoe, the MAASP the critical factors for well killing.

Once the kick is inside the casing, the pressure rating of surface

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

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

Driller’s

Method

Driller’s Method

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

Driller’s Method

Procedure

• 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

Driller’s Method

Procedure

• While Kill Mud fill-up the drill string

– ICP decrease to FCP • Kill Mud at the bit

– Stop the pump, close the choke

– Observe casing and drill pipe pressure Casing Pressure = SIDPP

SIDPP = 0 • Start the pump

– Open choke, bring pump to Kill Pump Rate – Casing pressure keep constant

Driller’s Method

Procedure

• 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

Drillers Method P(bar) ICP= 71 SP= 10 + KPP= 28 + FCP= 31 SIDPP= 33 Drillers Method P(bar) MAASP 3 = 134 MAASP 2 = 73 LOT LOT = 100 Pa max = 92 SIDPP= 33 SICP= 45

Driller’s Method

• Simple calculations → Easy 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.

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

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.

Wait & Weight Method

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

– Open choke, bring pump to Kill Pump Rate

Wait & Weight Method

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

–

Stop the pump, close the choke

–

Observe casing and drill pipe pressure

Drill Pipe Pressure = 0

Casing Pressure › SICP

Wait & Weight Method

Procedure

•

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

Secondary Well Control

Wait & Weight & Driller’s Methods

P_DP P_ST

P_C1

P_C2 P_C2

Standpipe Pressure for Driller’s Method

Standpipe Pressure for W&W Method

W&W: Well killed at SIDPP

.. due to change in ρ_mud

Wait & Weight Method

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 openhole

VOLUMETRIC METHOD

Volumetric Method is applied to a well if the hole condition

is 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

VOLUMETRIC METHOD APPLICATION

• The Volumetric Method Application has the same concept of

“Constant Bottom Hole Pressure Technique” as the other well

control methods have.

• Choke manifold is connected to the Trip Tank.

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

• BHP maintains constant because BHP = SICP + HPmud

VOLUMETRIC METHOD APPLICATION

• Volumetric Method Application has the same concept of “Constant

Bottom Hole Pressure Technique” as the other well control methods

have.

• Choke manifold is connected to the Trip Tank.

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

VOLUMETRIC METHOD APPLICATION

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 choke at every cycle.

Pressure Increase: (bar or psi)

Selected working pressure on the casing gauge for every cycle.

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

Capacity of the place where gas influx is located in the hole.

WELL CONFIGURATION:

• After pulling out of the hole a kick is taken and the well is shut-in by blind 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 psi

VOLUMETRIC METHOD

KILL EXERCISE

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

VOLUMETRIC METHOD KILL EXERCISE

T

100

BOP CLOSED

SICP= 100 psi VOLUMETRIC METHOD

KILL EXERCISE TRIP TANK MANUAL CHOKE CHOKE LINE Mud Density = 12.6 ppg Mud Gradient = 0.655 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 cycle Ca (bbl/ft): Capacity of the place where gas influx is located in the hole. MG (psi/ft): Drilling mud gradient in use.