Table Average Displacements For Range Drill Pipe

Size of

Actual

Displacement

Outer

Nominal

Weight

Diameter

Weight

in Air

bbl/90 ft

(in.)

(lbm/ft)

Tool-Joint Type

(lbm/ft)

(ft/bbl)

(bbl/ft)

Stand

23/s

6.65

internal flush

6.90

398.4

0.00251

0.23

2%

10.40

internal flush

10.90

251.9

0.00397

0.36

slim hole

10.40

263.0

0.00379

0.34

3 V2

13.30

full hole

13.90

197.6

0.00506

0.46

slim hole

13.40

204.9

0.00488

0.44

internal flush

13.80

199.2

0.00502

0.45

15.50

internal flush

16.02

171.5

0.00583

0.52

4

14.00

full hole

15.10

181.8

0.00550

0.50

internal flush

15.10

176.1

0.00568

0.51

4Vz

16.60

full hole

17.80

154.3

0.00648

0.58

xtrahole

18.00

152.7

0.00655

0.59

slim hole

17.00

161.6

0.00619

0.56

internal flush

17.70

155.3

0.00644

0.58

20.00

xtrahole

21.40

128.5

0.00778

0.70

full hole

21.30

129.0

0.00775

0.70

slim hole

20.50

134.0

0.00746

0.67

internal flush

21.20

129.5

0.00772

0.69

22.82

xtrahole

24.10

114.0

0.00877

0.79

32.94

xtrahole

36.28

75.7

0.01320

1.19

5

19.50

xtrahole

20.60

133.3

0.00750

0.68

25.60

xtrahole

26.18

107.4

0.00932

0.84

42.00

xtrahole

45.2 ±

60.8 ±

0.0165 ±

1.48±

the bottom of the hole to the surface if the pump factor is 0.1781 bbl/cycle.

Solution. For field units of feet and barrels, Eq. 1.13 becomes

bbl/ft.

Using Table 1.5, the inner diameter of 5-in., 19.5 lbm/ft drillpipe is 4.276 in.; thus, the capacity of the drillpipe is

4.2762

1,029.4

and the capacity of the drill collars is 2.752

1,029.4

The number of pump cycles required to circulate new mud to the bit is given by

  • 0.01776 (7,000) + 0.00735 (500)]bbl
  • 719 cycles.

0.1781 bbl/cycle

Similarly, the annular capacity outside the drillpipe is given by

1,029.4

and the annular capacity outside the drill collars is 9.8752 - 82

capacity of pipe

capacity of annulus Aa = flii-if)

displacement of pipe

Fig. 1.40-Capacity and displacement nomenclature.

The pump cycles required to circulate mud from the bottom of the hole to the surface is given by

0.1781 bbl/cycle

1,029.4

1.7 The Well Control System

The well control system prevents the uncontrolled flow of formation fluids from the wellbore. When the bit penetrates a permeable formation that has a fluid pressure in excess of the hydrostatic pressure exerted by the drilling fluid, formation fluids will

Bradenhead
Fig. 1.41 - Kick detection during drilling operations.

begin displacing the drilling fluid from the well. The flow of formation fluids into the well in the presence of drilling fluid is called a kick. The well control system permits (1) detecting the kick, (2) closing the well at the surface, (3) circulating the well under pressure to remove the formation fluids and increase the mud density, (4) moving the drillstring under pressure, and (5) diverting flow away from rig personnel and equipment.

Failure of the well control system results in an uncontrolled flow of formation fluids and is called a blowout. This is perhaps the worst disaster that can occur during drilling operations. Blowouts can cause loss of life, drilling equipment, the well, much of the oil and gas reserves in the underground reservoir, and damage to the environment near the well. Thus, the well control system is one of the more important systems on the rig.

Kick detection during drilling operations usually is achieved by use of a pit-volume indicator or a flow indicator. The operation of these devices is illustrated in Fig. 1.41. Both devices can detect an increase in the flow of mud returning from the well over that which is being circulated by the pump.

Pit volume indicators usually employ floats in each pit that are connected by means of pneumatic or electrical transducers to a recording device on the rig floor. The recording device indicates the volume of all active pits. High- and low-level alarms can be preset to turn on lights and horns when the pit volume increases or decreases significantly. An increase in surface mud volume indicates that formation fluids may be entering the well. A decrease indicates that drilling fluid is being lost to an underground formation.

Mud flow indicators are used to help detect a kick

Drill Table Arrangement
Fig. 1.42-Two alternative trip-tank arrangements for kick detection during tripping operations.

more quickly. The more commonly used devices are somewhat similar in operation to the pit level indicators. A paddle-type fluid level sensor is used in the flowline. In addition, a pump stroke counter is used to sense the flow rate into the well. A panel on the rig floor displays the flow rate into and out of the well. If the rates are appreciably different, a gain or loss warning will be given.

While making a trip, circulation is stopped and a significant volume of pipe is removed from the hole. Thus, to keep the hole full, mud must be pumped into the hole to replace the volume of pipe removed. Kick detection during tripping operations is accomplished through use of a hole fill-up indicator. The purpose of the hole fill-up indicator is to measure accurately the mud volume required to fill the hole. If the volume required to fill the hole is less than the volume of pipe removed, a kick mav be in progress.

Small trip tanks provide the best means of monitoring hole fill-up volume. Trip tanks usually hold 10 to 15 bbl and have 1-bbl gauge markers. Two alternative trip-tank arrangements are illustrated in Fig. 1.42. With either arrangement, the hole is maintained full as pipe is withdrawn from the well. Periodically, the trip tank is refilled using the mud pump. The top of a gravity-feed type trip tank must be slightly lower than the bell nipple to prevent mud from being lost to the flowline. The required fill-up volume is determined by periodically checking the fluid level in the trip tank. When a trip tank is not installed on the rig, hole fill-up volume should be determined by counting pump strokes each time the hole is filled. The level in one of the active pits should not be used since the active pits are normally too large to provide sufficient accuracy.

Bell Nipple For Bop
Fig. 1.43-Example ram-type blowout preventer.

The flow of fluid from the well caused by a kick is stopped by use of special pack-off devices called blowout preventers (BOP's). Multiple BOP's used in a series are referred to collectively as a BOP stack. The BOP must be capable of terminating flow from the well under all drilling conditions. When the drillstring is in the hole, movement of the pipe without releasing well pressure should be allowed to occur. In addition, the BOP stack should allow fluid circulation through the well annulus under pressure. These objectives usually are accomplished by using several ram preventers and one annular preventer.

An example of a ram preventer is shown in Fig. 1.43. Ram preventers have two packing elements on opposite sides that close by moving toward each other. Pipe rams have semicircular openings which match the diameter of pipe sizes for which they are designed. Thus the pipe ram must match the size of pipe currently in use. If more than one size of drillpipe is in the hole, additional ram preventers must be used in the BOP stack. Rams designed to close when no pipe is in the hole are called blind rams. Blind rams will flatten drillpipe if inadvertently closed with the drillstring in the hole but will not stop the flow from the well. Shear rams are blind rams designed to shear the drillstring when closed. This will cause the drillstring to drop in the hole and will stop flow from the well. Shear rams are closed on pipe only when all pipe rams and annular preventers have failed. Ram preventers are available for working pressures of 2,000, 5,000, 10,000, and 15,000 psig.

Annular preventers, sometimes called bag-type preventers, stop flow from the well using a ring of synthetic rubber that contracts in the fluid passage. The rubber packing conforms to the shape of the pipe in the hole. Most annular preventers also will close an open hole if necessary. A cross section of one tyDe of annular preventer is shown in Fig. 1.44. Annular preventers are available for working pressures of 2,000, 5,000, and 10,000 psig.

Both the ram and annular BOP's are closed hydraulically. In addition, the ram preventers have a screw-type locking device that can be used to close the preventer if the hydraulic system fails. The annular preventers are designed so that once the rubber element contacts the drillstring, the well pressure helps hold the preventer closed.

Modern hydraulic systems used for closing BOP's are high-pressure fluid accumulators similar to those developed for aircraft fluid control systems. An example vertical accumulator is shown in Fig. 1.45. The accumulator is capable of supplying sufficient high-pressure fluid to close all of the units in the BOP stack at least once and still have a reserve. Accumulators with fluid capacities of 40, 80, or 120 gal and maximum operating pressures of 1,500 or 3,000 psig are common. The accumulator is maintained by a small pump at all times, so the operator has the ability to close the well immediately, independent of normal rig power. For safety, stand-by accumulator pumps are maintained that use a secondary power source. The accumulator fluid usually is a non-corrosive hydraulic oil with a low freezing point. The hydraulic oil also should have good lubricating characteristics and must be compatible with synthetic rubber parts of the well-control system.

The accumulator is equipped with a pressure-regulating system. The ability to vary the closing pressure on the preventers is important when it is necessary to strip pipe (lower pipe with the preventer closed) into the hole. If a kick is taken during a trip, it is best to strip back to bottom to allow efficient circulation of the formation fluids from the well. The

Blowout Preventer Control Systems
Fig. 1.44- Example annular-type blowout preventer.
Blowout Preventer Ram Type
Fig. 1.45- Example accumulator system.

application of too much closing pressure to the preventer during stripping operations causes rapid wear of the sealing element. The usual procedure is to reduce the hydraulic closing pressure during stripping operations until there is a slight leakage of well fluid.

Stripping is accomplished most easily using the annular preventer. However, when the surface well pressure is too great, stripping must be done using two pipe ram preventers placed far enough apart for external upset tool joints to fit between them. The upper and lower rams must be closed and opened alternately as the tool joints are lowered through.

Space between ram preventers used for stripping operations is provided by a drilling spool. Drilling spools also are used to permit attachment of high-pressure flowlines to a given point in the stack. These high-pressure flowlines make it possible to pump into the annulus or release fluid from the annulus with the BOP closed. A conduit used to pump into the annulus is called a kill line. Conduits used to release fluid from the annulus may include a choke line, a diverter line, or simply a flowline. All drilling spools must have a large enough bore to permit the next string of casing to be put in place without removing the BOP stack.

The BOP stack is attached to the casing using a casing head. The casing head, sometimes called the braden head, is welded to the first string of casing

Blowout Preventer Equalizer
Fig. 1.46- Example remote control panel for operating blowout preventers.

cemented in the well. It must provide a pressure seal for subsequent casing strings placed in the well. Also, outlets are provided on the casing head to release any pressure that might accumulate between casing strings.

The control panel for operating the BOP stack usually is placed on the derrick floor for easy access by the driller. The controls should be marked clearly and identifiably with the BOP stack arrangement used. One kind of panel used for this purpose is shown in Fig. 1.46.

The arrangement of the BOP stack varies considerably. The arrangement used depends on the magnitude of formation pressures in the area and on the type of well control procedures used by the operator. API presents several recommended arrangements of BOP stacks. Fig. 1.47 shows typical arrangements for 10,000- and 15,000-psi working pressure service. Note that the arrangement nomenclature uses the letter "A" to denote an annular preventer, the letter "R" to denote a ram preventer, and the letter "S" to denote a drilling spool. The arrangement is defined starting at the casing head and proceeding up to the bell nipple. Thus, Arrangement RSRRA denotes the use of a BOP stack with a ram preventer attached to the casing head, a drilling spool above the ram preventer, two ram preventers in series above the drilling spool,

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