18. well control equipment

TAMU - Pemex

Well Control

Lesson 18

Well 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

3

High Pressure Equipment

Casing

Casing Heads and Spools

Stack Equipment

Choke and Kill Line Equipment

Drillstem Control Equipment

4

5

6

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 0

9.0 10,100

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

0.0 5.0 10.0 15.0 20.0

Gradients, lb/gal

Dep

th,

ft

PPG

FPGGG BUG

7... (7.2) ... (7.3)

( > FG = 0.91 psi/ft )

( at the surface )

( at the shoe )

1

8

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 Pressure

0.0 04,718 10,100

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

0 2,000 4,000 6,000 8,000 10,000 12,000

Pressure, psig

Dep

th,

ft

PP

FP

GP

BUPGP

7,676

9

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 SF

9,211 05,368 10,100

0

2,000

4,000

6,000

8,000

10,000

12,000

0 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

10

Drillpipe rotation can cause severe erosion on the inside of the casing. Clearly, this can result in a loss of casing pressure integrity.

11

Casing Heads and Spools

After surface casing is set, the casing is cut

And wellhead is installed

BOPE is N/U on the

wellhead

12

Fig. 7.3 Casing Heads

and Spools

13

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.

14

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

15

Annular Preventers

From “Guide to Blowout Prevention” by WCS, the Well Control School

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Ram Preventer

Also, see Multimedia Lesson 2

17

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

r

pp

3002003.7

000,9pcl

18

Choke and Kill Line Equipment

Also, see Multimedia Lesson 2

Manual Choke Remote Hydraulic Choke

19

Drillstem Control Equipment

Also, see Multimedia Lesson 2

Backpressure Valves

Dart Type Valve

20

Control System Equipment and Design

Accumulator Design Principles

Other Components

Test Procedures

21

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

22

1,000 psig 1,150 psig 2,000 psig?

3,000 psigmaximum

23

One annular preventer three ram preventers

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25

149.4 gal

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27

28

29

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Low-Pressure Equipment

Manifold Lines

Mud-Gas Separators

Degassers

31

Mud-Gas Separators

Primary means of separating gas from mud while controlling a kick,

drilling underbalanced, or circulating large connection/trip gas.

32

Fig. 7.19Example Mud-Gas Separator

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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

34

35

150-ft vent line, three sharp bendsCirculation Rate = 175 gal/min

7 ft

Equivalent Length = 360 ft

Vent line Diameter = ?

Separator Diameter = ?

Mud Leg

Height =

36

37

ch

krvlvl V

qVq Peak Rate in Vent Line =

(time to vent gas)

38

This equation is based on giving the mud enough retention time for the gas to migrate upwards into the upper part of the chamber.

39

Degassers

Remove gas from the mud just downstream of the shale shaker

40

Vacuum Degasser

Gas Cut Mud

41

Equipment Arrangement: Design and Philosophy

Diverters

Stack Arrangement

Kill Line Considerations

Choke Line and Manifold Design

42

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

43

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

44

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.

45

Stack Configuration

A

46

Stack Configuration A

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Stack Configuration

B

48

Stack Configuration B

49

Stack Configuration

C

50

Stack Configuration C

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Stack Configuration

D

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Stack Configuration D

53

54

55

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Choke Line and Manifold Design

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Choke Line and Manifold Design

58

Fig. 7.28Example

High-Pressure

Choke Manifold