671 - BP Well Control Tool Kit 2002

8/10/2019 671 - BP Well Control Tool Kit 2002

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Version 2002.1 Released January 2002

WELL CONTROL TOOLKIT

2. Pressure Loss Calculator

Common Data Input

1. Kick Tolerance Calculator

4. Kill Sheet - Subsea BOPs3. Kill Sheet - Surface BOPs

5. Volumetric Control Sheets 6. Casing Pressure Profile

Unit Converter

For m ore inform at ion . . .

User Guide

QuitExcel

QuitToolki

2002


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249819044.xls.ms_office 11/2/2014 5:03 AM

COMMON DATA INPUT

Version 2002.1 Released January 2002 Units (UK/US): UK

Well No: Date: 7 09 07 SurFace or Subsea BOP Stack (F/S) ? f

Rig Name: Time: 1:09 PM Surface BOP Setup.

Casing / Hole Configuration Surface Drillstring Configuration

OD ID Depth Input Pipe OD ID Length

(inch) (inch) (m) ID (in): 3 (inch) (inch) (m)

Casing: 13.625 12.415 1430 Len (m): 150 Drillpipe 1: 5 4.8 4150

Liner 1: Choke Line Drillpipe 2:

Liner 2: ID (in): 3 HWDP: 7 4 50

Openhole Size (inch): 12.25 4400 Len (m): 100 DC: 8 2.8 200

Well Shut-in Data Drilling Mud Formation / Equipment Integrity

Shut-in Time (h:m): 9:30 AM Mud Weight (sg): 1.070 Openhole Weak Point MD (m): 2650

Bit MD (m): 4400 PV (cP): 30 Openhole Weak Point TVD (m): 2650

Bit TVD (m): 3190 YP (lbf/100sqft): 20 Min Leak-off /FIT EMW (sg): 1.120

Shut-in DP Pres (psi): 100 Surf Active Vol (bbl): 800 Max Leak-off /FIT EMW (sg): 1.180

Shut-in Csn Pres (psi): 100 Reserve Vol (bbl): 1000 Casing Burst Pressure (psi): 5000

Shut-in Pit Gain (bbl): 20 Baryte on Site (MT): 1000 Max Allowable Surf Pres (psi): 5000

Mud Pump Data SCR Data (mud return via flowline)

Liner Size Max Pres Vol Eff 100% Pump Pump 1: Pump 2:

(inch) (psi) % bbl/stk SPM bbl/min Pscr (psi) bbl/min Pscr (psi)

Pump 1: 5.5 5000 97 0.088 20 1.707 350 1.707 360

Pump 2: 5.5 5000 97 0.088 30 2.561 500 2.561 515

Pump 3: 5.5 5000 97 0.088 40 3.414 700 3.414 720

Formation Pressure / Temperature Bit Pressure Safety Factors:

Min Pore Pressure (sg): 1.03 Nozzles Surf Pres Safety Factor for Kick Toler (psi): 100Max Pore Pressure (sg): 1.07 (inch^2) Minimum Bottom Hole Over-B During Kill (psi): 100

Surface Temperature (deg.F): 80 0.451 Operating Margin for Vol Control (psi): 100

Weak Point Temperature (deg.F): 120 Operating Margin for Lubrication (psi): 100

Kick Zone Temperature (deg.F): 180

Well Profile

MD (m) TVD (m) MD X Y

Surface: 0 0 0 0 0

Kick-Off 1: 0 0 0 0 0

E d B ilt 1 0 0 0 0

9808

249

0

0 1000 2000 3000 4000

Horizontal Departure


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249819044.xls.ms_office Page 3 of 2

KICK TOLERANCE CALCULATORFor Vertical, Deviated or Horizontal Wells


Well: 9808 Units (UK/US): us

Kick Zone Parameters : Input Error Messages:1 Openhole Size ? (inch) 8.5 2 Measured Depth ? (ft) 64053 Vertical Depth ? (ft) 64054 Horizontal Length (>87 deg) ? (ft) Non-Horizontal

5 Tangent Angle Above Horizontal ? (deg)6 Min Pore Pressure Gradient ? (ppg) 10.0007 Max Pore Pressure Gradient ? (ppg) 10.0008 Kick Zone Temperature ? (deg.F) 100

Weak Point Parameters:9 Measured Depth ? (ft) 1800

10 Vertical Depth ? (ft) 180011 Section Angle (


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PRESSURE LOSS CALCULATORVersion 2002.1 Released January 2002 UK

Units (UK/US): UK

Weight PV YP Mud SCR Range

(sg) (cP) (lbf/100sqft) (bbl/min)

Original Mud: 1.100 30 20 Minimum: 1

Kill Weight Mud: 1.120 30 20 Maximum: 5

CHOKE LINE DIMENSION:Length ID

(m) (inch)

Section 1: 1000 3.5

Section 2: 0 0

Choke Line Pressur e Loss :

Mud SCR Pressure Loss (psi)

(bbl/min) Original Mud Kill Mud1 91 91

2 98 98

3 106 106

4 113 113

5 142 144

ANNULUS DIMENSION:Length Casing ID String OD

(m) (inch) (inch)

70.0 18.750 5.5

250.0 17.500 5.5

Annulus Pressure Loss:

Mud SCR Pressure Loss (psi)

(bbl/min) Original Mud Kill Mud

1 8 6 8 6

0

2040

60

80

100

120

140

160

0 2 4 6

Press

ure

Loss

(psi)

Slow Circulation Rate (bbl/min)

Original Mud Kill Mud

8 6

8.6

8.6

8.6

8.6

8.6

8.6

Pressure

Loss

(psi)

Original Mud Kill Mud


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249819044.xls.ms_office Page 5 of 3 11/2/2014 5:03 AM

KILL SHEETFor Vertical / Deviated Wells with Surface BOPs

Version 2002.1 Released January 2002 Units (UK/US): US

Well No: Rig: Date: 22-Jan-02 Time: 1:09 PMHole Size (inch): 12.25 Casing OD (inch): 13.375 Shoe TVD (ft): 4000 Shoe MD(ft) 4000

Openhole Weak Point: TVD (ft) 4000 MD (ft) 4000 Fracture Grad EMW (ppg): 13.50

Csn Burst (psi): 5020 Barite on Site (sack) 1000 Reserve Mud Vol (bbl): 1000

Drill String Contents (From Surface to Bottom)

OD ID (bbl/ft) Len (ft) Depth (ft) Vol (bbl) Cumulative Volume (bbl)

DP Size 1: 5 4.276 0.01777 9100 9100 161.7

DP Size 2: 0.00000 0 0.0 161.7

Heavy Weight DP: 5 3 0.00875 600 9700 5.2 166.9

Drill Collar: 8 2.5 0.00607 300 10000 1.8 168.8

Annulus Contents (From Surface to Bottom)

Casing/Hole ID Strg OD Capacity (bbl/ft) Len (ft) Depth (ft) Vol (bbl) Cumulative Volume (bbl)

Casing: 12.415 5 0.12549 4000 4000.00 502.0

12.25 5 0.12154 5100 9100.00 619.8 1121.8

12.25 5 0.12154 600 9700.00 72.9 1194.7

12.25 8 0.08364 300 10000.00 25.1 1219.8Surf Input Line: OD= ID= 3.00 in Length (ft): 150 Vol (bbl): 1.3

Choke Line: OD= ID= 3.00 in Length (ft): 100 Vol (bbl): 0.9

Total Circ System Vol (bbl): 1391 Surf Active (bbl): 800 Total Active Mud Vol (bbl): 2191

Pumping Data

Pump 1 Liner (in): 5.5 Max Pres (psi): 5000 Vol Eff (%): 97 100% bbl/stk: 0.088


PUMP 1 PUMP 2 KILL CIRCULATION TIMES (min)

SPM bbl/min Pscr bbl/min Pscr Pump No Surface to Bit Bit to Shoe Shoe to Chk Total

20 1.707 350 1.707 360 1 98.9 420.5 294.0 813

30 2.561 500 2.561 515 65.9 280.3 196.0 542

40 3.414 700 3.414 720 49.4 210.2 147.0 407

Kick Data Near vert ical well !

Time Shut-In: 9:30 AM Bit at TD (ft): 10000 TVD (ft): 10000

Mud Weight in Hole (ppg): 12.000 PV (cP): 30 YP (lbf/100ft^2): 20

SIDPP (psi): 400 Shut-in Casing Pres (psi): 600 Shut-in Pit Gain (bbl): 30

Test Case A1 Rig Name


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Kill Data

Kill Start Time: Kill Mud to Reach: Drill Bit: Choke: MAASPs (psi):

Keep this cell blank: 100 Pump Strokes: 1977 16268 Static: 312

Initial Circ Pres (psi): 900 Pump Pres (psi): 532 532 Circulating: 253

Standpipe Pressure (For Pumping Down Kill Mud Through Drill String)Section Point: MD (ft) TVD (ft) Vol (bbl) Strokes Time (min) Standpipe Pressure (psi)

From: Surface: 0 0 0.0 0 0 900 ( =Pic )

0 0.0 0 0.0

0.0 0 0.0

0 0.0 0 0.0

0.0 0 0.0

0.0 0 0.0

To: Drill Bit: 10000 10000 168.8 1977 65.9 532 ( =Pfc )

STANDPIPE PRESSURE TABLE

Pump Pred. DP Actual DP Actual Choke Pump Pred. DP Actual DP Actual Choke

Stroke Pres Pressure Pressure Stroke Pressure Pressure Pressure

(psi) (psi) (psi) (psi) (psi) (psi)

0 1500 1760 1342 17 31

110 1486 1870 1336 18 30

220 1472 1980 1329 19 29

1

2

3

16

15

14

0

100

200

300

400

500

600

700

800

900

1000

0 500 1000 1500 2000 2500

StandpipePres

sure(psi)

Pump Strokes to Bit (Stroke)

STANDPIPE PRESSURE CHART


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GENERAL KILL PROCEDURE

Pump Start Up Procedure: Pump Choke Drillpipe

~ When the choke pressure gauge starts to respond in each step, Speed Pressure Pressure

manipulate the choke valve to adjust the choke pressure (SPM) (psi) (psi)

according to the table on the right. 0 600 400

~ Zero the stroke counter when kill mud has reached rig floor. 6 600 500

~ When the pump has reached the kill speed, record the initial 12 600 600

circulating pressure and compare with the calculated value. 18 600 700

~ If the recorded and calculated values are close to each other, 24 600 800

continue the kill operation. If they are significantly different, stop 30 600 900

the pump, shut-in the well and investigate.

If choke pressure in the above table is constant, the conventional kill method will be used, which will ignore

Annular Pressure Loss (APL) to provide an over-balance pressure.

If choke pressure is decreasing during pump start up, the slimhole technique will be used, which will compensate

APL during kill. When APL is relatively high however, it may be impossible to fully compensate APL. In thiscase, the choke pressure will reduce to zero and the choke valve become wide-open during pump start up.

Displacing Drillpipe and Annulus with Kill Mud:

Once the pump has reached kill speed, the choke valve should be adjusted to control the DP pressure so that the

bottom hole pressure is maintained constant. This means that:

~ During the 1st complete circulation using Driller's method, the DP pressure be maintained constant at the

initial circulating pressure.

~ When kill weight mud is being pumped down the drillpipe (using either Driller's or W&W), the DP pressure

be adjusted according to the standpipe pressure chart & table shown in the 2nd page of the kill sheet.

Once the kill mud has entered into the annulus, the DP pressure should be maintained constant. However, at

some point when the annulus is being displaced by kill mud, or after the influx is out of hole, the choke valve

may become wide-open. From then on, DP pressure will increase gradually while choke valve is kept at

the full open position. This will continue until the kill mud reaches the choke, at which DP pressure should be

equal or close to the value shown in the "Kill Data" Section


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KILL SHEETFor Vertical / Deviated Wells with Subsea BOPs


Well No: Rig: Date: 02.oct.2003 Time: 1:09 PM

Hole Size (inch): 17.5 Casing OD (inch): 20 Shoe TVD (m) 2650 Shoe MD (m) 2650

Openhole Weak Point: TVD (m) 2650 MD (m) 2650 Fracture Grad EMW (sg): 1.15

Csn Burst (psi): 5000 Baryte on Site (MT): 1000 Reserve Mud Vol (bbl): 1000

Drill String Contents (From Surface to Bottom)

OD ID (bbl/m) Len (m) Depth (m) Vol (bbl) Cumulative Volume (bbl)

DP Size 1: 5.5 4.8 0.07342 3050 3050 223.9

DP Size 2: 0.00000 0 0.0 223.9

Heavy Weight DP: 7 4 0.05099 50 3100 2.5 226.5Drill Collar: 8 2.8 0.02498 90 3190 2.2 228.7

Annulus Contents (From Surface to Bottom)

Casing/Hole ID Strg OD Capacity (bbl/m) Len (m) Depth (m) Vol (bbl) Cumulative Volume (bbl)

Riser: 18.75 5.5 1.02394 1990 1990.0 2037.6

Casing: 18.75 5.5 1.02394 660 2650.0 675.8 2713.4

17.5 5.5 0.87954 400 3050.0 351.8 3065.3

17.5 7 0.81979 50 3100.0 41.0 3106.2

17.5 8 0.77199 90 3190.0 69.5 3175.7Surf Input Line: OD= ID= 3.00 in Length (m): 150 Vol (bbl): 4.3

Total Circ System Vol (bbl): 3409 Surf Active (bbl): 800 Total Active Mud Vol (bbl): 4209

Subsea Choke / Kill Line Setup

Choke Line Kill Line Sea Water Depth (m) 2000 Air Gap (m) -10

Section ID (in) Len (m) ID (in) Len (m) Fluid in Choke Line: Density (sg):

Subsea: 1990 1990 Fluid in Kill Line: Density (sg):

Surface:

Pumping DataPump 1 Liner (in): 5.5 Max Pres (psi): 5000 Vol Eff (%): 97 100% bbl/stk: 0.088


SCR Tests (Return from Riser) Kill Using Pump No.: 1

PUMP 1 PUMP 2 KILL CIRCULATION TIMES (min)

SPM bbl/min Pscr bbl/min Pscr Total Surface to Bit Bit to Shoe Shoe to BOP BOP to Chk

20 1.707 350 1.707 360 801 134.0 270.8 395.9 0.0

30 2.561 500 2.561 515 534 89.3 180.5 263.9 0.0

40 3 414 700 3 414 720 400 67 0 135 4 197 9 0 0

WFC Rig Name


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Conventio nal vert ical / high ang le Ki l l

Kill Data

Kill Start Time: Kill Mud to Reach: Drill Bit: Choke: MAASPs (psi):

Keep this cell blank: 100 Pump Strokes: 2680 16012 Static: 301

Initial Circ Pres (psi): 600 Pump Pres (psi): 510 510 Circulating: 285 Standpipe Pressure (For Pumping Down Kill Mud Through Drill String)

Section Point: MD (m) TVD (m) Vol (bbl) Strokes Time (min) Standpipe Pressure (psi)

From: Surface: 0 0 0.0 0 0 600 ( =Pic )

2000 2000 146.8 1720 57.3 544

#VALUE! #VALUE! #VALUE!

0.0 0 0.0

#VALUE! #VALUE! #VALUE!

0.0 0 0.0To: Drill Bit: 3190 3190 228.7 2680 89.3 510 ( =Pfc )

STANDPIPE PRESSURE TABLE

Pump Pred. DP Actual DP Actual Choke Pump Pred. DP Actual DP Actual Choke

Stroke Pres Pressure Pressure Stroke Pressure Pressure Pressure

(psi) (psi) (psi) (psi) (psi) (psi) (psi) (psi)

0 600 1440 553 7 5

90 597 1530 550 3 4

1

2

21

20

500

510

520

530

540

550

560570

580

590

600

610

0 500 1000 1500 2000 2500 3000 3500

StandpipePressure(psi)

Pump Strokes to Bit (Stroke)

STANDPIPE PRESSURE CHART


10/20


GENERAL KILL PROCEDURE

Shut-in surface choke pressure is 100 (pis) with 0 in choke line.

Surface choke pressure will become -2926 (psi) when choke line is displaced to mud in hole.

Shut-in surface kill line pressure is: 100 (psi) with 0 in kill line.

Kill line pressure becomes 100 (psi) when displaced to with (sg) =

Pump Start Up Procedure: Pump Choke Kill Line Drillpipe

~ Start the pump and increase its speed in small steps. Speed Pressure Pressure Pressure

~ When choke pressure gauge starts to respond in each (SPM) (psi) (psi) (psi)

step, manipulate choke valve to adjust choke/kill line 0 -2926 100 100

pressure according to the table on the right. 6 -2926 100 200

~ Zero stroke counter when kill mud reaches rig floor. 12 -2926 100 300

~ When pump has reached kill speed, record the initial 18 -2926 100 400

circulating pressure and compare with calculated value. 24 -2926 100 500

~ If the recorded and calculated values are close to each 30 -2926 100 600

other, continue the kill operation. If they are significantly different, stop pump, shut-in the well and investigate.

If the choke pressure in above table is constant, the conventional kill method will be used, which will ignore both

Choke Line Loss (CLL) and Annular Pressure Loss (APL) to provide an over-balance pressure.

If the choke pressure is decreasing during pump start up, the deep water and/or slimhole techniques will be used,

which will compensate CLL and/or APL during kill. When the shut-in surface choke pressure is relatively low

however, it may be impossible to fully compensate CLL and/or APL. In this case, the choke pressure will reduce

to zero and the choke valve become wide-open during pump start up.

Displacing Drillpipe and Annulus with Kill Mud:

Once the pump has reached kill speed, the choke valve should be adjusted to control the drillpipe pressure so that

the bottom hole pressure is maintained constant. This means that:

~ During the 1st complete circulation using Driller's method, the drillpipe pressure be maintained constant at the

initial circulating pressure.

~ When kill weight mud is being pumped down the drillpipe (using either Driller's or W&W), the drillpipe pressure

be adjusted according to the standpipe pressure chart & table shown in the 2nd page of the kill sheet.


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VOLUMETRIC CONTROL SHEETFor Controlling Gas Expansion During Well Shut-in

Version 2002.1 Released January 2002 Units (UK/US): USWell No: Test Case A1 Rig: Rig Name Date: 22-Jan-02 Time Well Shut-in: 1:09 PM

Open Hole Size (inch): 12.25 TD (ft): 10000 TVD (ft): 10000

Open Hole Weak Point: TD (ft): 4000 TVD (ft): 4000 Frac Gradient (ppg): 13

Shut-in DP Pres (psi): 500 Shut-in Csn Pres (psi): 750 MW in Hole (ppg): 12

Bottom Hole Pres on Shut-in (psi): 6734 = Pres Gradient (ppg): 12.962 Shut-in Pit Gain (bbl)

Weak Point Pressure on Shut-in (psi): 3244 = Pres Gradient (ppg): 15.609 20

Upper or Average Annular Capacity (bbl/ft): 0.12549 Annular Mud Hydrostatic (psi/bbl) 4.97

O-B Safety Factor (psi): 100 Operating Margin (psi): 100 = Equi Mud Vol (bbl): 20.13

Can drillpipe pressure gauge be used to monitor bottom hole pressure (Y/N) ? y

Volumetric Control LogFor Controlling Gas Expansion Before Reaching BOP Stack

Drillpipe Change in Mud Bled Hydrostatic Total Mud Over-B

Time Operation Pressure DP Pres at Choke Loss Bled Pressure

(hr:min) (psi) (+/- psi) (bbl) (psi) (bbl) (psi)

Shut-in Condition 500 ~ ~ ~ ~ 0

Add Over-B Safety Facotr: 600 100 ~ ~ ~ 100

Add operating margin 700 100 ~ ~ ~ 200

Bleed DP pres back to: 600 -100 0

Add operating margin 0 ~ ~ ~

0

0 ~ ~ ~

0

0 ~ ~ ~

0

0 ~ ~ ~0

0 ~ ~ ~

0

0 ~ ~ ~

0

0 ~ ~ ~

0

0


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LUBRICATION LOGFor Venting Gas From Beneath BOP Stack


Upper Annulus Casing ID (inch) : 12.415 String OD: 5 Annular Cap (bbl/ft): 0.12549

Lubricating MW (ppg) : 12 Hydrostatic (psi/bbl): 4.97 Operating Margin (psi): 100

Choke Change in Mud Vol Mud Vol Total Mud Hydrostatic

Time Operation Pressure Choke Pres Pumped in Bled out Pumped in Gain /Loss

(hr:min) (psi) (+/- psi) (bbl) (bbl) (bbl) (+/-psi)

Before lubrication start ~ ~ ~ ~~ ~ 0

~ ~ 0

~ 0

~ ~ 0

~ 0

~ ~ 0

~ 0

~ ~ 0~ 0

~ ~ 0

~ 0

~ ~ 0

~ 0

~ ~ 0

~ 0

~ ~ 0~ 0

~ ~ 0

~ 0

~ ~ 0

~ 0

~ ~ 0

~ 0

0


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CASING PRESSURE PROFILEDuring Circulating out a Gas Influx


Mud Weight in Hole (sg) 1.07 Openhole Weak Point MD (m) 2650

Shut-in Gas Influx Vol (bbl) 20 TVD (m) 2650

Shut-in Drillpipe Pressure (psi) 100 Surface Temp (deg.F): 80

B'hole Over-Balance (psi) 100 Bottom Hole Temp (deg.F): 180

Formation Pore Pressure (psi) 4950 Temp Gradient (deg.F/m) 0.0313

Annular Hole/Csg String Section Bottom Section Section Total Annular

Section ID OD TD TVD Length Volume Volume Capacity

No. (inch) (inch) (m) (m) (m) bbl (bbl) (bbl/m)

Surface: 18.750 5.500 0 0 ~ ~ ~ ~

1 18.750 5.500 1990.0 1990.0 1990.0 2037.6 3175.7 1.02394

2 18.750 5.500 2650.0 2650.0 660.0 675.8 1138.1 1.02394

3 17.500 5.500 3050.0 3050.0 400.0 351.8 462.3 0.87954

4 17.500 7.000 3100.0 3100.0 50.0 41.0 110.5 0.81979

5 17.500 8.000 3190.0 3190.0 90.0 69.5 69.5 0.77199

Weighted Average Annular Capacity (bbl/m): 0.99553

Max Pit Gain Volume (bbl) = 16.1 Max Surf Casing Pres (psi) = 5045

Max Weak Point Pres (psi) = 5050 Max Weak Point EMW (sg) = 1.341

Surface Casing & Weak Point Pressure Profiles

2000

3000

4000

5000

6000

4500

4600

4700

4800

4900

5000

5100

PointPressure(psi)

ingPressure(psi)


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UNIT CONVERTERVersion 2002.1 Released January 2002

Conversion To SI Units Conversion To Customary Units

Length Length

1 inch = 25.4 mm 100 mm = 3.93701 inch

1 ft = 0.3048 m 1 m = 3.28084 ft

1 mile = 1.60934 km 1 km = 0.62137 mile

Weight Weight

1 lbf = 0.45359 kg 1 kg = 2.20462 lb

1 MT = 1000 kg 1000 kg = 1 MT

Volume Volume

1 US gal = 3.78541 litre 1 litre = 0.26417 US gal

1 bbl = 158.987 litre 619 litre = 3.8934 bbl

1 ft^3 = 28.3168 litre 1 litre = 0.03531 ft^3

Velocity Velocity

100 ft/min = 0.508 m/s 1 m/s = 196.85 ft/min

100 ft/min = 30.48 m/min 1 m/min = 3.28084 ft/min

Volumetric Flow Rate Volumetric Flow Rate

100 gal/min = 6.30902 L/s 1 L/s = 15.8503 gal/min

1 bbl/min = 2.64978 L/s 1 L/s = 0.37739 bbl/min

1 MMscf/day = 327.774 L/s 100 bbl/min = 0.8085 MMscf/day

Pressure Pressure

100 psi = 6.89476 bar 1 bar = 14.5038 psi

100 psi = 689.476 kPa 29.9 kPa = 4.33663 psi

100 psi = 7.0307 kgf/cm^2 1 kgf/cm^2 = 14.2233 psi

Pressure Gradient Pressure Gradient

1 psi/ft = 22.6206 kPa/m 100 kPa/m = 4.42075 psi/ft0.7 psi/ft = 1.61305 sg 1 sg = 0.43396 psi/ft

10 ppg = 0.52 psi/ft

Density Density

1 lbm/US gal = 119.826 kg/m^3 1000 kg/m^3 = 8.34543 lbm/US gal

1 lbm/US gal = 0.11983 g/cm^3 1 g/cm^3 = 8.34543 lbm/US gal

1 lbm/ft^3 = 0.01602 g/cm^3 1 g/cm^3 = 62.4278 lb/ft^3

1 ppg = 7.48052 lb/ft^3

Concentration Concentration

1 lb /bbl 2 85301 k / ^3 1 k / ^3 0 35051 lb /bbl


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WELL CONTROL TOOLKIT 2002


Well Control Toolkit 2000 is a collection of Excel worksheets designed for drilling engineers and rig-site

personnel to record data and perform calculations related to well control.

Hardware & software requirement:

A PC running under the BP Common Operating Environment (COE3) with Excel 2000.

To run Toolkit:

~ To open Toolkit: Same way as you would do with an Excel file.

~ When you first open Toolkit, the Main Menu will appear on the screen.

~ Click on a button in Main Menu to open a worksheet.

~ Upon finishing a worksheet, click on "Return to Menu" button in the worksheet.

All the worksheets have the following common features:

1. User can choose to use either UK (m, sg) or US (ft, ppg) units. The ability to convert units has been

added to the Common Data Input Sheet, however UK and US units cannot be mixed.2. Easy to use: Just open a worksheet and input data into green cells, the results will be updated

automatically.

3. Data input is flexible: It can be done either in each of the worksheets directly, or imported from

"Common Data Input" sheet, or imported from a saved data file.

4. Some input cells have help-notes describing the input requirement. These cells have red triangle

on their top-right hand corners. Position and keep the prompt on the cell, the help-notes should

appear.

5. Critical inputs are automatically checked. If found unreasonable, error messages will appear.

6. Results are presented in both tabulated data and plots.

7. All data and plots are laid out such that they can be easily printed on letter-sized papers.

8. All plots are re-scaled automatically to fit input /output data range.

Common Data Input

"Common Data Input" (CDI) sheet is designed for entering well data, which can be then imported to

other worksheets. Use of this sheet to input data has following advantages:

1. It provides a single data input sheet for all other worksheets in Toolkit. So once this is filled in,

it t k l d t t lt ki k t l kill h t i fil t


16/20


drilling parameters and hole condition. It can be used for vertical, deviated or horizontal wells.

The principles used in KTC are similar with those described in BP Well Control Manuals (Volume 1).

However, KTC includes the effects of bottom hole pressure / temperature on gas density (for methanegas based on Hall & Yarborough's Equation of State). So it is more accurate, usually less conservative.

It can cope with many scenarios (e.g. shut-in influx length is longer or shorter than BHA, etc.).

Kick tolerance is defined as the maximum volume of kick influx that can be shut-in and

circulated out without breaking down the weak point formation.

Therefore, kick tolerance volume is determined based on two critical conditions:

~ When the influx is at the hole bottom under the initial shut-in condition.

~ When the influx top is displaced to the openhole weak point with the original mud weight.

It should be pointed out that, the pressure losses through annulus / choke lines and the possible choke

error are considered by assuming a Surface Pressure Safety Factor. Therefore, this surface pressure

safety factor should be the sum of:

1. A choke operator error margin (say 100 psi)

2. Pressure loss through the choke line.

For subsea BOPs, if the choke line pressure loss is to be compensated during kill by using

the kill sheet in this Toolkit, then it can be totally or partially ignored.

3) Pressure loss through the annulus above the openhole weak point.

In HPHT & ERD wells where there is a long casing & liner section, its annular pressure loss (APL)

can be high. If it is included in the pressure safety factor, kick tolerance volume will be significantly reduced. In this case, APL should be compensated during kill by using the Kill Sheets in this Toolkit.

In the mean time, APL can be totally or partially ignored in kick tolerance calculations.

In some cases, the calculated volume extends from bottom hole to above the casing shoe, which implies

that the well can tolerate an unlimited volume of kick without breaking down the weak point formation.

This often occurs when the vertical height of the openhole section is relatively short. If this occurs in a

high angle or horizontal hole section where potential kick volume can be high, it is important to check

the maximum allowable gas volume based on the casing burst strength and pressure ratings of BOP

stack & choke manifold. This can be done in the 2nd page of the calculator.

2. PRESSURE LOSS CALCULATOR

Pressure Loss Calculator is designed to calculate pressure losses through choke lines and openhole

/ casing annuli. The methods are based on the simple models as described in "Applied Drilling

Engineering", SPE Textbook, 1986. The calculator can be used for:

~ Estimating the pressure safety factor in Kick Tolerance Calculator.

Thi h b d ib d i th i ti


17/20


For Vertical / Deviated Wells With Surface BOPs

The Kill Sheet is designed to record data during drilling operations and to perform kill calculations when

a well has been shut-in on a kick.

This kill sheet can be used for:

~ Land or offshore rigs with surface BOPs.

~ Vertical, deviated or horizontal wells (Straight, L- or S-shaped holes).

~ Conventional or small hole sizes

~ Single- or dual-sized drillpipe strings (plus HWDPs and DCs).

~ Gas, oil or water kicks.

Kill TechniquesThis kill sheet incorporates both the conventional kill techniques (Drillers or W&W), where annular

pressure loss (APL) is ignored, and the special kill technique where APL will be compensated. The

advantage of the special kill technique is that it will result in lower wellbore pressures during kill , thus

minimising the risk of formation breakdown at the weak point. This is particularly important in ERD,

HPHT or small hole wells where APL can be high due to long / small casing annulus.

Before deciding on which kill technique to use, APL is calculated using two alternative methods:

~ Based on SCR test data, where APL is obtained by subtracting the string and bit losses from the SCR

pump pressure. This method is often more accurate when APL is relatively high (e.g. in small holes).

~ Direct calculation, where APL is calculated based on annular sizes and mud properties. This is often more accurate when APL is relatively low (e.g. in conventional hole sizes).

Based on the above APL values, user can input an "Accepted APL" in the "Pressure Losses" section.

A suitable kill technique will then be selected:

~ If APL 150 psi and SICP is sufficiently high, then the special kill technique will be used to

compensate APL during kill. User will be required to select an over-balance safety factor in the

"Kill Data" section.~ If APL > 150 psi but SICP is low, then APL can only be partially compensated.

The actual kill technique to be used will be displayed below the "Pressure Losses" section.

Kill Procedures:

At the end of the kill sheet (page 3), some guidance is also given on kill procedures and how to use the

kill sheet, etc.

4. KILL SHEET

F V ti l / D i t d W ll With S b BOP


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significantly higher. If ignored, it can result in excessive pressures in the wellbore and the consequence

of formation breaking down at the open hole weak point. The deep water kill technique should be used

in this case to compensate the CLL.

In this kill sheet, CLL is first calculated. Based on the calculated value and perhaps other rig-site tests,

user can then input an accepted CLL for compensation during kill. This is done in the "Pressure Losses"

section of the kill sheet. The Annular pressure loss (APL) can also be compensated if it is high. This

is done in a similar way as in the previous kill sheet for Surface BOPs.

Kill Techniques:

Once user has defined the accepted choke line loss (CLL) and annular pressure loss (APL) in "Pressure

Losses" section, a suitable kill technique will be selected:

A. If CLL 100psi, the combination of deep water and slimhole kill techniques will be used to compensate both CLL and APL. User will be required to select an over-balance safety

factor in the "Kill Data" section. If SICP is low (after choke line has been displaced to mud), however,

CLL and APL will be only partially compensated.

The actual kill technique to be used will be displayed above the "Kill Data" section.

Kill Procedures:

At the end of the kill sheet (page 3), some guidance is also given on kill procedures and how to use the

kill sheet, etc.

5. VOLUMETRIC CONTROL SHEETS

The volumetric control techniques are used during well shut-in period to control gas expansion due to

migration. The purposes of the techniques are to:

1) Maintain the bottom hole pressure above the formation pressure to prevent further influx, and

2) Control the bottom hole pressure below a preset limit to prevent formation breakdown.

For swabbed kicks, the techniques can be used as the final kill. For under-balanced kicks, however,

the techniques only provide a temporary measure to control the wellbore pressure. The final kill can

l b hi d b i l ti kill d i t th h l Th f th t h i l d h


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For more detailed information about the volumetric control techniques, please refer to:

BP Well Control Manuals, Vol.I, Chapter 6, Section 2.

6. CASING PRESSURE PROFILES

This spreadsheet program is designed to calculate the casing pressure profiles at the casing shoe

and surface when displacing a given volume of gas influx to surface. The calculations are based on

the following assumptions:

1) The influx is free gas.

For mixed influxes (gas/oil/water), only the gas component is considered.

2) The influx is a single gas bubble.

Calculations based on this assumption usually give higher pressures and thus, it is conservative.3) The mud displacing the influx has the original mud weight (Driller's method). If kill mud weight

was used (Wait & Weight method), the casing shoe and surface pressures may be lower.

Therefore, the pressure predictions from this program will be conservative.

UNIT CONVERTER

All the worksheets in this Toolkit have been designed for both the UK (m.sg) and US (ft.ppg) oil

industry units. This should cover most of the world-wide operations within BP. However, if you find

any units used in your local operations are different from those in the worksheets, then this unitConverter can be used to convert your local units into either the UK or US units.


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249819044.xls.ms_office 11/2/2014 5:03 AM


FOR USE WITH EXCEL 2000

DISCLAIMERThis Toolkit has been developed by BP Exploration Operating Company Limited ("BP") for

internal use only. The calculations are based on the latest well control techniques andprocedures. Every effort has been made to ensure their correctness as well as their field

applicability. However, BP makes no warranty of any kind, express or implied, with respect

to this Toolkit including, but not limited to, the implied warranties of mechantability andfitness for any purpose. BP shall have no liability for any loss or damage, however causedand of whatever nature, arising directly or indirectly from the use of this Toolkit.

No tool, however powerfu l and accurate, can ever replace sound prof essional

ju dgem en t in th e fi el d to en sure that saf e and sound techn iq ues and pro ced ure s are

fol low ed in a well control event.

Original Author - Yuejin Luo

For more information or help, please contact:Jonny Gent, E-mail: [email protected] Billard, E-mail: [email protected]

Documents

671 - BP Well Control Tool Kit 2002