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PETE 625Well Control
Lesson 18Well Control Equipment
2
Well Control Equipment High Pressure Equipment Casing Design Control System Equipment and Design BOPE Inspection and Testing Low-Pressure Equipment Equipment Arrangement:
- Design and Philosophy
Assignments
HW # 11: Ch 6, Problems 1, 3, 5, 11 and 19
Due Friday, July 16
Read: Chapters 6 & 7
ScheduleProject Abstracts are due on Friday,
July 16. Type-written, less than one page. Drilling topic.
QUIZ B: Monday, July 12, 9-11 a.m. in Room 407M.
Project Presentations: Monday, July 19
FINAL: Wednesday, July 21, 9-11 a.m. in Room 511
5
High Pressure Equipment Casing
Casing Heads and Spools
Stack Equipment
Choke and Kill Line Equipment
Drillstem Control Equipment
6
7
8
Gradient Depthlb/gal ft
Pore Press. Grad.16.0 016.0 12,900
Frac.Press. Grad17.53 017.53 10,100
Gas Gradient2.89 0 2.89 10,100
Backup Grad.9.0 09.0 10,100
0
2,000
4,000
6,000
8,000
10,000
12,000
14,0000.0 5.0 10.0 15.0 20.0
Gradients, lb/gal
Dep
th,
ft
PPG
FPGGG BUG
9... (7.2) ... (7.3)
( > FG = 0.91 psi/ft )
( at the surface )
( at the shoe )
1
10
Pressure Depthpsig ft
Pore Pressure0.0 0
10,712 12,900
Fracture Pressure0.0 0
9,191 10,100
Gas Pressure7,676 0 9,191 10,100
10,292 10,10010,712 12,900
Backup Pressure0.0 0
4,718 10,100
0
2,000
4,000
6,000
8,000
10,000
12,000
14,0000 2,000 4,000 6,000 8,000 10,000 12,000
Pressure, psig
Dep
th,
ft
PP
FP
GP
BUP GP
7,676
11
Pressure Depthpsig ft
Gas Pressure7,676 09,191 10,100
Backup Pressure0 0
4,718 10,100
Press. Difference7,676 0 4,473 10,100
Design w/1.2 SF9,211 05,368 10,100
0
2,000
4,000
6,000
8,000
10,000
12,0000 2,000 4,000 6,000 8,000 10,000
Pressure, psig
Dep
th,
ft
Final Design
BUP GP
Preliminary Design
7,676 9,211
5,3684,473
12
Drillpipe rotation can cause severe erosion on the inside of the casing. Clearly, this can result in a loss of casing pressure integrity.
13
Casing Heads and Spools
After surface casing is set, the casing is cut
And wellhead is installed
BOPE is N/U on the
wellhead
14
Fig. 7.3 Casing Heads
and Spools
15
Stack Equipment Basic functions:
Seal the well against the drillstring or open hole and contain well pressure
Provide a a full-bore opening to allow passage of drilling and testing tools
Permit unrestricted flow of fluids to the choke line while the preventers are closed.
16
Stack Equipment Basic functions:
Allow drillstring movement when the well is shut-in to prevent sticking or allow stripping
Provide a way to allow fluids to be pumped into the well below a closed preventer
Convey drilling fluid to the bell nipple and flowline
17
Annular Preventers
From “Guide to Blowout Prevention” by WCS, the Well Control School
18
Ram Preventer
Also, see Multimedia Lesson 2
19
Example 7.2 Given:
Closing ratio for rams is 7.3
SIP = 9,000 psi
Closing friction = 200 psi
Control-fluid friction loss = 300 psi
What is the minimum closing pressure?
Eq. 7.6 yields
pcl = 1,733 psig
cfcpcl
wcl pp
rpp
3002003.7
000,9pcl
20
Choke and Kill Line Equipment
Also, see Multimedia Lesson 2
Manual Choke Remote Hydraulic Choke
21
Drillstem Control Equipment
Also, see Multimedia Lesson 2
Backpressure Valves
Dart Type Valve
22
Control System Equipment and Design
Accumulator Design Principles
Other Components
Test Procedures
23
Accumulator Design Principles
Store hydraulic fluid under pressure to operate the BOPE.
Most utilize a precharge pressure of 1,000 psig and have a working pressure of 3,000 psig.
Precharge supplies the driving energy when the bottle is fully depleted
24
1,000 psig 1,150 psig 2,000 psig?
3,000 psigmaximum
25
One annular preventer three ram preventers
26
27
149.4 gal
28
29
30
31
32
Low-Pressure Equipment
Manifold Lines
Mud-Gas Separators
Degassers
33
Mud-Gas Separators
Primary means of separating gas from mud while controlling a kick,
drilling underbalanced, or circulating large connection/trip gas.
34
Fig. 7.19Example Mud-Gas Separator
35
Excessive friction pressure in flare line
…can cause evacuation of the separator and gas can blow through mud outlet
The allowable separator pressure is equal to:
pml = gm*hml
Eq 7.8, The Weymouth equation can be used to predict gas friction pressure
36
37
150-ft vent line, three sharp bendsCirculation Rate = 175 gal/min
7 ft
Equivalent Length = 360 ft
Vent line Diameter = ?Separator Diameter = ?
Mud LegHeight =
38
39
ch
krvlvl V
qVq Peak Rate in Vent Line =
(time to vent gas)
40
This equation is based on giving the mud enough retention time for the gas to migrate upwards into the upper part of the chamber.
41
Degassers
Remove gas from the mud just downstream of the shale shaker
42
Vacuum Degasser
Gas Cut Mud
43
Equipment Arrangement: Design and Philosophy
Diverters
Stack Arrangement
Kill Line Considerations
Choke Line and Manifold Design
44
Diverters Diverters are used when the decision
has been made to NOT shut-in the well on a kick
Usually done prior to setting surface casing
Fear is that shutting in the well would result in formation fracture and broaching to the surface
45
Diverter System
Diverter Lines should be sized as large as practical for two reasons.
1. To keep two phase friction down, and,
2. Prevent plugging
46
Diverters When a well is put on diverter, the well
is out of control, and the goal is to restore control as quickly as
possible.
This is done by pumping mud as fast as the pumps can while increasing the mud weight.
47
Stack Configuration
A
48
Stack Configuration A
49
Stack Configuration
B
50
Stack Configuration B
51
Stack Configuration
C
52
Stack Configuration C
53
Stack Configuration
D
54
Stack Configuration D
55
56
57
58
Choke Line and Manifold Design
59
Choke Line and Manifold Design
60
Fig. 7.28Example
High-Pressure
Choke Manifold