WELL CONTROL TOOLKIT 2002
For more information . . .
Common Data Input 1. Kick Tolerance Calculator
2. Pressure Loss Calculator
3. Kill Sheet - Surface BOPs
4. Kill Sheet - Subsea BOPs
5. Volumetric Control Sheets
6. Casing Pressure Profile
Unit Converter Quit Excel
Version 2002.1 Released January 2002
User Guide Quit Toolki
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COMMON DATA INPUT Units (UK/US):
Version 2002.1 Released January 2002 Well No:
9808
Date:
7 09 07
Rig Name:
249
Time:
1:09 PM
Casing / Hole Configuration
Casing:
OD
ID
Depth
(inch)
(inch)
(m)
13.625
12.415
1430
SurFace or Subsea BOP Stack (F/S) ? f Surface BOP Setup.
Surface Input Pipe ID (in): Len (m):
150
Choke Line
Liner 2:
ID (in): 12.25
4400
Mud Weight (sg):
ID (inch)
(m)
5
4.8
4150
Drillpipe 1:
Length
HWDP:
7
4
50
DC:
8
2.8
200
100
Drilling Mud
9:30 AM
OD (inch) Drillpipe 2:
3
Len (m):
Well Shut-in Data Shut-in Time (h:m):
Drillstring Configuration
3
Liner 1: Openhole Size (inch):
UK
Formation / Equipment Integrity 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
(inch)
(psi)
%
bbl/stk
SPM
bbl/min
Pump 1: Pscr (psi)
bbl/min
Pump 2: 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):
100
Max 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
Surface:
0
0
0
Kick-Off 1:
0
0
0 0
Kick-off 2:
0
End-Built /Drop 2:
0
Bit:
4400
3190
For Kick Tolerance only:
0 0
0
0
0
0
0
0
0
0
1500
0
0
0
2000
4400
3030
3190
500
Vertical Depth
End-Built 1: DP Cross-Over:
0
0
X Y Horizontal Departure 0 0 1000 2000 0 0
1000
3000
2500
Angle below Weak Point (deg): Angle at Bit Depth (deg): Angle above Horizontal (deg):
3000 3500
Horizontal Section Length (m):
Surface BOPs: Keep Following Green Cells Blank !
0 0
0
4000
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KICK TOLERANCE CALCULATOR For Vertical, Deviated or Horizontal Wells Version 2002.1 Released January 2002
Well:
9808
Units (UK/US):
Kick Zone Parameters:
us
Input Error Messages:
1 2 3 4 5 6 7 8
Openhole Size ? Measured Depth ? Vertical Depth ? Horizontal Length (>87 deg) ? Tangent Angle Above Horizontal ? Min Pore Pressure Gradient ? Max Pore Pressure Gradient ? Kick Zone Temperature ?
9 10 11 12 13 14
Measured Depth ? Vertical Depth ? Section Angle (<87 deg) ? Min Fracture Gradient / EMW ? Max Fracture Gradient / EMW Weak Point Temperature ?
15 16 17 18 19
(inch) (ft) (ft) (ft) (deg) (ppg) (ppg) (deg.F)
8.5 6405 6405 Non-Horizontal 10.000 10.000 100
Weak Point Parameters: (ft) (ft) (deg) (ppg) (ppg) (deg.F)
1800 1800 20.000 20.000 100
Drill Collar OD ? Drill Collar Length ? Drillpipe OD ? Surface Pressure Safety Factor ? Mud Weight in Hole ?
(inch) (ft) (inch) (psi) (ppg)
6.25 200 5.5 0 9.500
Annular Capacity Around BHA: Annular Capacity Around DP:
(bbl/ft) (bbl/ft)
0.03224 0.04080
(psi) (psi/ft)
981 0.0416
Other Parameters:
At least 100 psi !
At Min Fracture Gradient:
Comments:
Circulating MAASP Gas Gradient at Weak Point For Min Pore Pressure: Max Allowable Gas Height: Kick Tolerance: For Max Pore Pressure: Max Allowable Gas Height: Kick Tolerance:
(ft) (bbl)
1804 33.3
(ft) (bbl)
1804 33.3
At Max Fracture Gradient: Circulating MAASP Gas Gradient at Weak Point For Min Pore Pressure: Max Allowable Gas Height: Kick Tolerance: For Max Pore Pressure: Max Allowable Gas Height: Kick Tolerance:
(psi) (psi/ft)
981 0.0416
(ft) (bbl)
1804 33.3
(ft) (bbl)
1804 33.3
Min Fracture Grad
Max Fracture Grad
35
Min Fracture Grad Max Fracture Grad 10.00 33 33 10.00 33 33 10.00 33 33
Kick Tolerance (bbl)
30
25 20
15 10
5 0 0.00
2.00
4.00
6.00
8.00
10.00
12.00
Pore Pressure Gradient
APPENDIX:
Maximum Allowable Gas Influx Volume Based on Casing Burst & Surface Equipment Rating
Max Allowable Surface Pressure ? Near Surface Casing ID ? Near Surface Annular Temperature ? Gas Gradient at Max Surface Pres: Near Surface Annular Capacity:
(psi) (inch) (deg.F) (psi/ft) (bbl/ft)
5000 12.8 80 0.100 0.12976
At Minimum Pore Pressure Gradient: Max Allowable Gas Height at Surface: Max Allowable Gas Vol. on Shut-in:
(ft) (bbl)
12300 infinite
(ft) (bbl)
12300 infinite
Comments: Extends to hole TD
At Maximum Pore Pressure Gradient: Max Allowable Gas Height at Surface: Max Allowable Gas Vol. on Shut-in:
Extends to hole TD
Max Allowable Gas Volume (bbl)
2500 2000
10.00 10.00 10.00
1500
2205 2205 2205
1000 500 0 0.00
2.00
4.00
6.00 Pore Pressure Gradient
8.00
10.00
12.00
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PRESSURE LOSS CALCULATOR Version 2002.1 Released January 2002
UK Units (UK/US):
Weight (sg) 1.100 1.120
Original Mud: Kill Weight Mud:
PV (cP) 30 30
YP (lbf/100sqft) 20 20
CHOKE LINE DIMENSION: ID (inch) 3.5 0
Choke Line Pressure Loss: Mud SCR Pressure Loss (psi) (bbl/min) Original Mud Kill Mud 1 91 91 2 98 98 3 106 106 4 113 113 5 142 144
0
2
Original Mud
String OD (inch) 5.5 5.5
Annulus Pressure Loss: Mud SCR Pressure Loss (psi) (bbl/min) Original Mud Kill Mud 1 8.6 8.6 2 8.6 8.6 3 8.6 8.6 4 8.6 8.6 5 8.6 8.6
4
6
Slow Circulation Rate (bbl/min)
Kill Mud
8.6 Pressure Loss (psi)
Casing ID (inch) 18.750 17.500
Kill Mud
160 140 120 100 80 60 40 20 0
ANNULUS DIMENSION: Length (m) 70.0 250.0
Mud SCR Range (bbl/min) Minimum: 1 Maximum: 5
Original Mud
Pressure Loss (psi)
Section 1: Section 2:
Length (m) 1000 0
UK
8.6 8.6 8.6 8.6 8.6 8.6 8.6 0
2 4 Slow Circulation Rate (bbl/min)
6
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KILL SHEET For Vertical / Deviated Wells with Surface BOPs Version 2002.1 Released January 2002 Well No:
Test Case A1
Hole Size (inch):
12.25
Openhole Weak Point: Csn Burst (psi):
Rig:
Rig Name
Casing OD (inch): TVD (ft)
5020
Shoe TVD (ft):
22-Jan-02 4000
Time:
US 1:09 PM
Shoe MD(ft)
4000
MD (ft)
4000
Fracture Grad EMW (ppg):
13.50
Barite on Site (sack)
1000
Reserve Mud Vol (bbl):
1000
4000
13.375
Date:
Units (UK/US):
Drill String Contents (From Surface to Bottom) OD
ID
(bbl/ft)
Len (ft)
Depth (ft)
Vol (bbl)
5
4.276
0.01777
9100
9100
161.7
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
DP Size 1: DP Size 2:
0.00000
Cumulative Volume (bbl)
Annulus Contents (From Surface to Bottom) Casing/Hole ID Casing:
Strg OD
Capacity (bbl/ft)
Len (ft)
Depth (ft)
Vol (bbl)
Cumulative Volume (bbl)
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
1219.8
150
Vol (bbl):
100
Vol (bbl):
Surf Input Line:
OD=
Choke Line:
OD=
Total Circ System Vol (bbl):
1391
ID=
3.00 in
Length (ft):
ID=
3.00 in
Length (ft):
Surf Active (bbl):
800
Total Active Mud Vol (bbl):
1.3 0.9 2191
Pumping Data Pump 1 Liner (in):
5.5
Max Pres (psi):
5000
Vol Eff (%):
97
100% bbl/stk:
0.088
Pump 2 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
20
1.707
350
1.707
360
30
2.561
500
2.561
40
3.414
700
3.414
Pump No Surface to Bit
Bit to Shoe
Shoe to Chk
Total
98.9
420.5
294.0
813
515
65.9
280.3
196.0
542
720
49.4
210.2
147.0
407
1
Kick Data Time Shut-In: 9:30 AM Mud Weight in Hole (ppg): SIDPP (psi):
400
Kill MW (ppg), MW2=
Bit at TD (ft): 12.000
10000
Near vertical well ! TVD (ft):
10000
PV (cP):
30
YP (lbf/100ft^2):
20
Shut-in Casing Pres (psi):
600
Shut-in Pit Gain (bbl):
30
12.769
Barite Required (lb/bbl):
50.4
Total (sack):
1104.7
Pressure Losses Kill Pump SPM:
30
bbl/stroke: 0.08536 Kill Rate (bbl/min) SCR Pres (psi):
Bit Nozzles
Circ Pressure Losses (psi): Surf Input Pipe:
Annular Pressure Loss (APL) (psi):
6
APL - Based on SCR Test:
169
2.561
(in^2)
Inside Drill String:
262
APL - Directly Calculated:
142
500
0.451
Drill Bit:
63
Accepted APL:
Conventional vertical / high angle kill
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Kill Data Kill Start Time: Keep this cell blank: Initial Circ Pres (psi):
Kill Mud to Reach: 100 900
Pump Strokes: Pump Pres (psi):
Standpipe Pressure Section Point:
Choke:
1977 532
16268 532
TVD (ft)
Vol (bbl)
Strokes
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
0.0 168.8
0 1977
0.0 65.9
0
10000
10000
MAASPs (psi): Static: Circulating:
312 253
(For Pumping Down Kill Mud Through Drill String)
MD (ft)
From: Surface:
To: Drill Bit:
Drill Bit:
Time (min)
Standpipe Pressure (psi) 900
( =Pic )
532
( =Pfc )
STANDPIPE PRESSURE CHART
1000
Standpipe Pressure (psi)
900 800 700 600 500 400 300 200 100 0 0
500
1000
1500
2000
2500
Pump Strokes to Bit (Stroke)
STANDPIPE PRESSURE TABLE Pump
Pred. DP
Actual DP
Actual Choke
Pump
Pred. DP
Actual DP
Actual Choke
Stroke
Pres (psi)
Pressure (psi)
Pressure (psi)
Stroke
Pressure (psi)
Pressure (psi)
Pressure (psi)
0
1500
1
16
1760
1342
17
31
110
1486
2
15
1870
1336
18
30
220
1472
3
14
1980
1329
19
29
330
1458
4
13
2090
1323
20
28
440
1445
5
12
2200
1317
21
27
550
1435
6
11
2310
1310
22
26
660
1425
7
10
2420
1304
23
25
770
1415
8
9
2530
1298
24
24
880
1405
9
8
2640
1291
25
23
990
1395
10
7
2750
1285
26
22
1100
1385
11
6
2860
1279
27
21
1210
1375
12
5
2970
1272
28
20
1320
1368
13
4
3080
1266
29
19
1430
1361
14
3
3190
1260
30
18
1540 1650
1355 1348
15 16
2 1
3222 1258 31 Hereafter maintain DP pressure constant @
17 1258 psi
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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
(SPM)
(psi)
(psi)
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
30
600
900
manipulate the choke valve to adjust the choke pressure according to the table on the right.
continue the kill operation. If they are significantly different, stop 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 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 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.
Complete Kill Operation: ~ When the kill mud has returned to surface, stop the pump and close the choke valve to check drillpipe and choke pressures. ~ If both drillpipe and choke pressures are zeros, open the BOP and further flow-check the annulus. ~ A further complete circulation should be carried out. In the mean time, a suitable overbalance should be added to the mud weight.
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KILL SHEET For Vertical / Deviated Wells with Subsea BOPs Version 2002.1 Released January 2002 Well No:
WFC
Hole Size (inch):
Rig: 17.5
Rig Name
Casing OD (inch):
Date:
20
Shoe TVD (m)
Openhole Weak Point: TVD (m) 2650 MD (m) Csn Burst (psi): 5000 Baryte on Site (MT):
2650 1000
Units (UK/US):
02.oct.2003 2650
Time:
UK 1:09 PM
Shoe MD (m)
2650
Fracture Grad EMW (sg): Reserve Mud Vol (bbl):
1.15 1000
Drill String Contents (From Surface to Bottom) DP Size 1:
OD
ID
(bbl/m)
Len (m)
Depth (m)
Vol (bbl)
5.5
4.8
0.07342
3050
3050
223.9
0
DP Size 2:
0.00000
Heavy Weight DP:
7
4
Drill Collar:
8
2.8
Cumulative Volume (bbl)
0.0
223.9
0.05099
50
3100
2.5
226.5
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)
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
3175.7
Length (m): 800
150 Vol (bbl): Total Active Mud Vol (bbl):
Surf Input Line: OD= Total Circ System Vol (bbl):
ID= 3.00 in Surf Active (bbl):
3409
Cumulative Volume (bbl)
4.3 4209
Subsea Choke / Kill Line Setup Choke Line Section
ID (in)
Subsea: Surface:
Kill Line
Len (m)
ID (in)
1990
Sea Water Depth (m)
Len (m)
2000
Air Gap (m)
Fluid in Choke Line:
Density (sg):
Fluid in Kill Line:
Density (sg):
1990
-10
Pumping Data Pump 1 Liner (in): Pump 2 Liner (in):
5.5 5.5
Max Pres (psi): Max Pres (psi):
SCR Tests (Return from Riser) PUMP 1
5000 5000
Vol Eff (%): Vol Eff (%):
97 97
Kill Using Pump No.:
1
PUMP 2
100% bbl/stk: 100% bbl/stk:
0.088 0.088
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 40
2.561 3.414
500 700
2.561 3.414
515 720
534 400
89.3 67.0
180.5 135.4
263.9 197.9
0.0 0.0
YP (lbf/100ft^2):
20
Kick Data Time Shut-In: 9:30 AM Mud Weight in Hole (sg): SIDPP (psi): 100 Kill MW (sg), MW2=
Bit at TD (m): 1.070
3190 PV (cP):
Near vertical well ! TVD (m): 3190 30
Shut-in Casing Pres (psi): 100 1.092 Barytes Required (lb/bbl):
Shut-in Pit Gain (bbl): 10.4 Total (MT):
20 19.9
Pressure Losses Kill Pump SPM:
30
bbl/stroke: 0.08536 Kill Rate (bbl/min) SCR Pres (psi):
2.561 500
Bit Nozzles (in^2) 0.451
Circ Pressure Losses (psi):
Annular Pressure Loss (APL) (psi):
Surf Input Pipe:
20
APL - Based on SCR Test:
214
Inside Drill String: Drill Bit:
220 47
APL - Directly Calculated: User Accepted APL:
32
SCR Pressure Through Choke (psi):
500
Calculated Choke Line Loss (CLL) (psi):
0
User Accepted CLL (psi):
0
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Conventional vertical / high angle Kill Kill Data Kill Start Time: Keep this cell blank: Initial Circ Pres (psi):
Kill Mud to Reach: 100 600
Pump Strokes: Pump Pres (psi):
Standpipe Pressure Section Point: From: Surface:
To: Drill Bit:
Drill Bit:
Choke:
2680 510
16012 510
MAASPs (psi): Static: Circulating:
(For Pumping Down Kill Mud Through Drill String)
MD (m)
TVD (m)
Vol (bbl)
Strokes
Time (min)
0
0
0.0
0
0
600
2000
2000
544
3190
3190
301 285
146.8
1720
57.3
#VALUE!
#VALUE!
#VALUE!
0.0
0
0.0
#VALUE!
#VALUE!
#VALUE!
0.0 228.7
0 2680
0.0 89.3
Standpipe Pressure (psi)
510
( =Pic )
( =Pfc )
STANDPIPE PRESSURE CHART 610
Standpipe Pressure (psi)
600 590 580 570 560 550 540 530 520 510 500 0
500
1000
1500
2000
2500
3000
3500
Pump Strokes to Bit (Stroke)
STANDPIPE PRESSURE TABLE Pump Stroke (psi) 0 90 180 270 360 450 540 630 720 810 900 990 1080 1170 1260 1350
Pred. DP Pres (psi) 600 597 594 591 588 585 582 579 576 574 571 568 565 562 559 556
Actual DP Pressure (psi) 1 2 3 4 5 6 7 8 9 0 1 2 3 4 5 6
Actual Choke Pressure (psi) 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6
Pump Pred. DP Actual DP Stroke Pressure Pressure (psi) (psi) (psi) 1440 553 7 1530 550 3 1620 547 9 1710 544 0 1800 541 1 1890 538 2 1980 535 3 2070 532 4 2160 528 5 2250 525 6 2340 522 7 2430 519 8 2520 516 9 2610 513 0 2680 510 1 Hereafter maintain DP pressure constant @
Actual Choke Pressure (psi) 5 4 3 2 1 0 9 8 7 6 5 4 3 2 1 510 psi
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GENERAL KILL PROCEDURE Shut-in surface choke pressure is
100
Surface choke pressure will become
-2926
Shut-in surface kill line pressure is: Kill line pressure becomes
100
100
(pis) with
0 in choke line.
(psi) when choke line is displaced to mud in hole. (psi) with
0
(psi) when displaced to
in kill line. 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
6
-2926
100
200
~ Zero stroke counter when kill mud reaches rig floor.
pressure according to the table on the right.
12
-2926
100
300
~ When pump has reached kill speed, record the initial
18
-2926
100
400
circulating pressure and compare with calculated value. ~ If the recorded and calculated values are close to each
24 30
-2926 -2926
100 100
500 600
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. Once the kill mud has entered into the annulus, the drillpipe 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, drillpipe 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 drillpipe pressure should be equal or close to the value shown in the "Kill Data" Section.
Complete Kill Operation: ~ When the kill mud has returned to surface, stop the pump and close the choke valve to check the drillpipe and choke pressures. ~ If both drillpipe and choke pressures are zeros, start to implement procedures for removing the gas possibly trapped in BOP stack. Then displace the riser annulus to kill mud. ~ Open the BOP and further flow-check the annulus. ~ A further complete circulation should be carried out. In the mean time, a suitable overbalance should be added to the mud weight.
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VOLUMETRIC CONTROL SHEET For Controlling Gas Expansion During Well Shut-in Version 2002.1 Released January 2002
Units (UK/US):
US
Well 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 Log For Controlling Gas Expansion Before Reaching BOP Stack Time (hr:min)
Operation Shut-in Condition Add Over-B Safety Facotr: Add operating margin Bleed DP pres back to: Add operating margin
Drillpipe Pressure (psi)
Change in DP Pres (+/- psi)
Mud Bled at Choke (bbl)
Hydrostatic Loss (psi)
Total Mud Bled (bbl)
Over-B Pressure (psi)
500 600 700 600
~ 100 100 -100 0
~ ~ ~
~ ~ ~
0 100 200
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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LUBRICATION LOG For Venting Gas From Beneath BOP Stack Version 2002.1 Released January 2002
Upper Annulus Casing ID (inch) : Lubricating MW (ppg) :
12
12.415
Hydrostatic (psi/bbl):
Choke Time
Operation
(hr:min)
Pressure (psi)
Before lubrication start
String OD:
Change in
5 4.97
Mud Vol
Choke Pres Pumped in
Annular Cap (bbl/ft): Operating Margin (psi):
0.12549 100
Mud Vol
Total Mud
Hydrostatic
Bled out
Pumped in
Gain /Loss (+/-psi)
(+/- psi)
(bbl)
(bbl)
(bbl)
~
~
~ ~
~ ~ ~
~ ~ ~
~ ~
~
~ ~
~
~ ~
~
~ ~
~
~ ~
~
~ ~
~
~ ~
~
~ ~
~
~ ~
~
~ ~
~
~ ~
~
~ ~
~
~ ~
~
~ ~
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 0 0 0 0
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CASING PRESSURE PROFILE During Circulating out a Gas Influx Units (UK/US):
Version 2002.1 Released January 2002
Mud Weight in Hole (sg) Shut-in Gas Influx Vol (bbl) Shut-in Drillpipe Pressure (psi) B'hole Over-Balance (psi) Formation Pore Pressure (psi) Annular Section No.
Hole/Csg ID (inch)
String OD (inch)
Surface: 1 2 3 4 5
18.750 18.750 18.750 17.500 17.500 17.500
5.500 5.500 5.500 5.500 7.000 8.000
1.07 20 100 100 4950
UK
Openhole Weak Point MD (m) TVD (m) Surface Temp (deg.F): Bottom Hole Temp (deg.F): Temp Gradient (deg.F/m)
Section Bottom TD TVD (m) (m)
Section Length (m)
Section Volume bbl
0 0 ~ ~ 1990.0 1990.0 1990.0 2037.6 2650.0 2650.0 660.0 675.8 3050.0 3050.0 400.0 351.8 3100.0 3100.0 50.0 41.0 3190.0 3190.0 90.0 69.5 Weighted Average Annular Capacity
Max Pit Gain Volume (bbl) = 16.1 Max Weak Point Pres (psi) = 5050
2650 2650 80 180 0.0313
Total Volume (bbl)
Annular Capacity (bbl/m)
~ 3175.7 1138.1 462.3 110.5 69.5 (bbl/m):
~ 1.02394 1.02394 0.87954 0.81979 0.77199 0.99553
Max Surf Casing Pres (psi) = 5045 Max Weak Point EMW (sg) = 1.341
Surface Casing & Weak Point Pressure Profiles 5100
6000
5000
Weak Point Pressure (psi)
4800
4000
4700 4600
3000
4500 2000
4400 4300
1000
4200
Weak Point Pressure Surface Casing Pressure
4100 0
500
1000
1500
2000
2500
Mud Volume Pumped (bbl)
3000
3500
0 4000
Surface Casing Pressure (psi)
5000
4900
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UNIT CONVERTER Version 2002.1 Released January 2002
Conversion To SI Units 1 1 1 1 1 1 1 1 100 100 100 1 1 100 100 100 1 0.7
1 1 1
1 1 100 1
Length inch = 25.4 mm ft = 0.3048 m mile = 1.60934 km Weight lbf = 0.45359 kg MT = 1000 kg Volume US gal = 3.78541 litre bbl = 158.987 litre ft^3 = 28.3168 litre Velocity ft/min = 0.508 m/s ft/min = 30.48 m/min Volumetric Flow Rate gal/min = 6.30902 L/s bbl/min = 2.64978 L/s MMscf/day = 327.774 L/s Pressure psi = 6.89476 bar psi = 689.476 kPa psi = 7.0307 kgf/cm^2 Pressure Gradient psi/ft = 22.6206 kPa/m psi/ft = 1.61305 sg Density lbm/US gal = 119.826 lbm/US gal = 0.11983 lbm/ft^3 = 0.01602
kg/m^3 g/cm^3 g/cm^3
Concentration lbm/bbl = 2.85301 kg/m^3 lbm/bbl = 2.85301 g/L Temperature deg.F = 37.2778 deg.C Temperature Gradient deg.F/ft = 1.82269 deg.C/m
Conversion To Customary Units 100 1 1 1 1000 1 619 1 1 1 1 1 100 1 29.9 1 100 1 10 1000 1 1 1 1 1 165 1
Length = 3.93701 inch = 3.28084 ft = 0.62137 mile Weight kg = 2.20462 lb kg = 1 MT Volume litre = 0.26417 US gal litre = 3.8934 bbl litre = 0.03531 ft^3 Velocity m/s = 196.85 ft/min m/min = 3.28084 ft/min Volumetric Flow Rate L/s = 15.8503 gal/min L/s = 0.37739 bbl/min bbl/min = 0.8085 MMscf/day Pressure bar = 14.5038 psi kPa = 4.33663 psi kgf/cm^2 = 14.2233 psi Pressure Gradient kPa/m = 4.42075 psi/ft sg = 0.43396 psi/ft ppg = 0.52 psi/ft Density kg/m^3 = 8.34543 lbm/US gal g/cm^3 = 8.34543 lbm/US gal g/cm^3 = 62.4278 lb/ft^3 ppg = 7.48052 lb/ft^3 Concentration kg/m^3 = 0.35051 lbm/bbl g/L = 0.35051 lbm/bbl Temperature deg.C = 329.9 deg.F Temperature Gradient deg.C/m = 0.54864 deg.F/ft mm m km
* Conversion factors are based on "The SI Metric System of Units and SPE Metric Standard", API, June 1984
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WELL CONTROL TOOLKIT 2002 Version 2002.1 Released January 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 takes only seconds to get results on kick tolerance, kill sheet, or casing pressure profiles, etc. 2. CDI sheet can be saved or imported separately from the Toolkit (top of sheet). 3. It is easier to input data into CDI. For example, there is no need to mentally work out how many annular sizes based on casing and drillstring data. This will be done automatically when importing data into kill sheets or casing annular pressure profile. 4. It allows visual checks on well profiles once MD/TVD data have been inputted at kick-off, end-build, etc. 5. The ability to convert units has been added, however UK and US units cannot be mixed. 6. The ability to save data from all the sheets (workbook) has been added (right side). This feature will save or reimport data directly to the worksheets (includes data not included in the CDI).
1. KICK TOLERANCE CALCULATOR Kick Tolerance Calculator (KTC) is designed to determine kick tolerance volumes, given well geometry
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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 methane gas 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. This has been described in the previous section. ~ Estimating the over-pressure during a conventional kill operation. If a conventional method is used in a kill operation, the pressure loss through annulus is ignored to provide an over-pressure at the kick zone to prevent further influx from coming into the wellbore. This calculator can be used to estimate the magnitude of this over-pressure. ~ Estimating the annular pressure loss in small hole drilling. When hole size is relatively small (e.g. < 6"), the annular pressure loss may be high. If ignored as in a conventional kill method, the high annular pressure loss may cause formation breaking down. In this case, the special well control technique should be used, which will compensate the annular pressure loss. The kill sheets as described in the following will facilitate the implementation of the technique.
3. KILL SHEET
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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 Techniques This 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, the conventional technique will be used where APL is ignored; You can choose to ignore APL in any case by keeping the "Accepted APL" cell blank. ~ 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 For Vertical / Deviated Wells With Subsea BOPs This kill sheet is designed for deep water drilling with subsea BOPs. It can be used to record data during drilling operations, and to perform kill calculations. The kick sheet is designed for: ~ Offshore floating rigs where there are long choke /kill lines from the subsea BOP to rig floor. ~ 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. The major difference between kill calculations for surface and subsea BOPs is in the choke line loss (CLL). On a land or an offshore fixed rig with surface BOPs, CLL is usually low at kill pump rates and can be ignored during kill operations. On a floating rig with subsea BOPs however, CLL can be
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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 and APL <= 100psi, both CLL and APL will be ignored. In this case, the conventional vertical / high angle kill technique will be used. You can choose to ignore both APL and CLL in any case by keeping the "Accepted APL" and "Accepted CLL" cells blank. B. If CLL > 100psi but APL <= 100psi, the deep water kill technique will be used to compensate CLL and APL will be ignored. When SICP is low (after choke line has been displaced to mud), however, CLL may be only partially compensated. C. If CLL <= 100psi but APL > 100 psi, the slimhole kill technique will be used to compensate APL and CLL will be ignored. When SICP is low (after choke line has been displaced to mud), however, APL may be only partially compensated. D. If CLL > 100 psi and APL > 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 only be achieved by circulating kill mud into the hole. Therefore the techniques are only used when circulating kill is impossible due to pumps breakdown, string washout, plugged bit nozzles or string off-bottom, etc. Also it is worthwhile to mention that volumetric control of an influx is only necessary when the influx contains free-gas which is migrating up the annulus. Three techniques are included in the Toolkit: 1) Volumetric control using drillpipe pressure gauge This is a relatively simple and accurate technique to control gas expansion. It should be used when there is communication between drillpipe pressure gauge and the wellbore annulus. 2) Volumetric control using choke pressure gauge This technique is a less reliable technique for controlling gas expansion. So it is only used when use of DP pressure is impossible due to string washout, plugged nozzles or string off-bottom, etc. 3) Static Lubrication The technique is used to vent gas from beneath BOP stack (both surface and subsea).
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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 unit Converter can be used to convert your local units into either the UK or US units.
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DISCLAIMER This 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 and procedures. 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 and fitness for any purpose. BP shall have no liability for any loss or damage, however caused and of whatever nature, arising directly or indirectly from the use of this Toolkit. No tool, however powerful and accurate, can ever replace sound professional judgement in the field to ensure that safe and sound techniques and procedures are followed in a well control event.
Original Author - Yuejin Luo For more information or help, please contact: Jonny Gent, E-mail:
[email protected] Alan Billard, E-mail:
[email protected]
Version 2002.1 Released January 2002 FOR USE WITH EXCEL 2000
