Oil Well Blowout Preventer Stripper Rubber Power Points

CASING '"If* vir' CASING '"IK VlT CASING 4«

■tIL SPOOL JPT <1L SPOOL JPT SPOOL JR"

Rotating sleeve —

Rotating assembly Lip-type seals

Quick-release bonnet

Quick-release bonnet hatch

Body

Kelly drive assembly £

Double roller bearings

Kelly drive assembly £

Double roller bearings

Quick-release bonnet

Quick-release bonnet hatch

Body

Bop Mud Return Line

Mud return line connector

Stripper rubber

FiH-up line connection

Fig. 1.48-Cutaway view of rotating blowout preventer.

Mud return line connector

Stripper rubber

FiH-up line connection

  1. 1.47-Typical surface stack blowout preventer arrangements for 10,000- and 15,000-psi working pressure service.
  2. 1.48-Cutaway view of rotating blowout preventer.

and an annular preventer above the ram preventers.

In some cases, it may be desirable to conduct drilling operations with a slight surface pressure on the annulus. A rotating head, which seals around the kelly at the top of the BOP stack, must be used when this is done. A rotating-type BOP is shown in Fig. 1.48. Rotating heads most commonly are employed when air or gas is used as a drilling fluid. They also can be used when formation fluids are entering the well very slowly from low-permeability formations. However, this practice is dangerous unless the formation being drilled has a very low permeability. This must be established from experience gained in drilling in the local area. For example, this practice is known to be safe in the Ellenberger formation in some areas of west Texas.

When the drillstring is in the hole, the BOP stack can be used to stop only the flow from the annulus. Several additional valves can be used to prevent flow from inside the drillstring. These valves include kelly cocks and internal blowout preventers. Shown in Fig. 1.49 is an example kelly cock. Generally, an upper kelly cock having left-hand threads is placed above the kelly and a lower kelly cock having right-hand threads is placed blow the kelly. The lower kelly cock also is called a drillstem valve. Two kelly cocks are required because the lower position might not be accessible in an emergency if the drillstring is stuck in the hole with the kelly down.

An internal BOP is a valve that can be placed in the drillstring if the well begins flowing during tripping operations. Ball valves similar to the valve shown in Fig. 1.49 also can be used as an internal BOP. In addition, dart-type (check-valve) internal BOP's (Fig. 1.50) are available. This type of internal BOP should be placed in the drillstring before drillpipe is stripped back in the hole because it will permit mud to be pumped down the drillstring after reaching the bottom of the well. Internal BOP's are installed when needed by screwing into the top of an open drillstring with the valve or dart in the open position. Once the BOP is installed, the valve can be closed or the dart released.

A high-pressure circulating system used for well control operations is shown in Fig. 1.51. The kick normally is circulated from the well through an adjustable choke. The adjustable choke is controlled from a remote panel on the rig floor. An example choke and a control panel are shown in Figs. 1.52 and 1.53. Sufficient pressure must be held against the well by the choke so that the bottomhole pressure in the well is maintained slightly above the formation pressure. Otherwise, formation fluids would continue to enter the well.

Mechanical stresses on the emergency high-pressure flow system can be quite severe when handling a kick. The rapid pressure release of large volumes of fluid through the surface piping frequently is accompanied by extreme vibrational stresses. Thus, care should be taken to use the strongest available pipe and to anchor all lines securely against reaction thrust. Also, some flexibility in the piping to and from the wellhead is required. The weight of all valves and fittings should be supported on structural members so that bending stresses are net created in the piping. Because of fluid abrasion, the number of bends should be minimized. The bends required should be sweep-turn bends rather than sharp "L" turns, or have an abrasion-resistant target at the point of fluid impingement in the bend.

API8 presents several recommended choke

Stem "0" ring\

Operating ' stem

Operating ' stem

Wrench

Wrench

Dart Oil Wells

Corrugated spring

Fig. 1.49- Example kelly cock.

Ball Seat "0" ring Body

"0" ring

Corrugated spring

Sub ft

PARTS LIST

Item

Part t>

10 11

Main Sub Sealing Sub Setting Tool Assy. Spider with Guide

Dart

Dart Rubber Hold Down Bar Base Stand Releasing Pin Setting Tool Handle

Suggested txtra Parts: 1 each: Spider w/Guide Spring Dart Rubber

Shaffer Inside Blowout Preventer in Holder

  1. 1.49- Example kelly cock.
  2. 1.50-Example dart-type internal blowout preventer.

manifold arrangements for 2,000, 3,000, 5,000, 10,000, and 15,000 psig working pressure systems. In addition to these recommendations, well operators have developed many other optional designs. The arrangement selected must be based on the magnitude of the formation pressures in the area and the well control procedures used by the operator. Shown in Fig. 1.51 is one of the alternative API arrangements. In this arrangement, a hydraulically controlled valve separates the BOP stack from the choke manifold. This valve normally is closed during drilling operations to prevent drilling mud solids from settling in the choke system. The controls that operate this valve are placed on the BOP control panel so that the BOP can be operated easily. Two adjustable chokes would allow kick circulation to continue in the event one of the adjustable chokes fails.

A mud gas separator permits any produced formation gases to be vented. Also, valves are arranged so that the well fluids can be diverted easily to the reserve pit to prevent excessive pressure from fracturing shallow formations below a short casing string.

The kill line permits drilling fluid to be pumped down the annulus from the surface. This procedure is used only under special circumstances and is not part of a normal well control operation. The kill line most frequently is needed when subsurface pressure during a kick causes an exposed formation to fracture and to begin rapidly taking drilling fluid from the upper portion of the hole.

1.8 Well-Monitoring System

Safety and efficiency considerations require constant monitoring of the well to detect drilling problems quickly. An example of a driller's control station is shown in Fig. 1.54. Devices record or display parameters such as (1) depth, (2) penetration rate, (3) hook load, (4) rotary speed, (5) rotary torque, (6) pump rate, (7) pump pressure, (8) mud density, (9) mud temperature, (10) mud salinity, (11) gas content of mud, (12) hazardous gas content of air, (13) pit level, and (14) mud flow rate.

In addition to assisting the driller in detecting drilling problems, good historical records of various aspects of the drilling operation also can aid geological, engineering, and supervisory personnel. In some cases, a centralized well-monitoring system housed in a trailer is used (Fig. 1.55). This unit provides detailed information about the formation being drilled and fluids being circulated to the surface in the mud as well as centralizing the record keeping of drilling parameters. The mud logger carefully inspects rock cuttings taken from the shale shaker at regular intervals and maintains a log describing their appearance. Additional cuttings are labeled according to their depth and are saved for further study by the paleontologist. The iden-

tification of the microfossils present in the cuttings assists the geologist in correlating the formations being drilled. Gas samples removed from the mud are analyzed by the mud logger using a gas chromatograph. The presence of a hydrocarbon reservoir often can be detected by this type of analysis.

Recently, there have been significant advances in subsurface well-monitoring and data-telemetry systems. These systems are especially useful in monitoring hole direction in nonvertical wells. One of the most promising techniques for data telemetry from subsurface instrumentation in the d'rillstring to the surface involves the use of a mud pulser that sends information to the surface by means of coded pressure pulses in the drilling fluid contained in the drillstring. One system, illustrated in Fig. 1.56, uses a bypass valve to the annulus to create the needed pressure signal.

1.9 Special Marine Equipment

Special equipment and procedures are required when drilling from a floating vessel. The special equipment is required to (1) hold the vessel on location over the borehole and (2) compensate for the vertical, lateral, and tilting movements caused by wave action against the vessel. Vessel motion problems are more severe for a drillship than for a semisubmersible. However, drillships usually are less expensive and can be moved rapidly from one location to the next.

A special derrick design must be used for drillships because of the tilting motion caused by wave action. The derrick of a drillship often is designed to withstand as much as a 20° tilt with a full load of drillpipe standing in the derrick. Also, special pipe-handling equipment is necessary to permit tripping operations to be made safely during rough weather. This equipment permits drillpipe to be laid down quickly on a pipe rack in doubles or thribbles rather than supported in the derrick. A block guide track also is used to prevent the traveling block from swinging in rough weather.

Most floating vessels are held on location by anchors. When the ocean bottom is too hard for conventional anchors, anchor piles are driven or cemented in boreholes in the ocean floor. The vessel is moored facing the direction from which the most severe weather is anticipated. A drillship has been designed that can be moored from a central turret containing the drilling rig. The ship is rotated about the turret using thrusters mounted in the bow and stern so that it always faces incoming waves. Most mooring systems are designed to restrict horizontal vessel movement to about 10% of the water depth for the most severe weather conditions; however, horizontal movement can be restricted to about 3% of the water depth for the weather conditions experienced 95% of the time. As many as 10 anchors are used in a mooring system. Several common anchor patterns are shown in Fig. 1.57.

A few vessels have large thrust units capable of holding the drilling vessel on location without anchors. This placement technique is called dynamic positioning. The large fuel consumption required for

Cutaway View Lateral Drilling
Fig. 1.51 - Schematic of example high-pressure circulating system for well control operations.
Choke Manifold Operation
Fig. 1.52-Example choke manifold showing 15,000-psi hand-adjustable choke and 15,000-psi remote adjustable choke.
Blowout Preventer Schematic
Fig. 1.53—Example control panels for remote adjustable choke.
Fig. 1.54-Example driller's control unit.

dynamic positioning is economically feasible only when (1) frequent location changes are required or (2) the lengths of the anchor lines required are excessive. Also, the range of weather conditions that can be sustained is more limited for dynamic positioning. Dynamic positioning generally is not used in water depths of less than 3,000 ft.

The position of the vessel with reference to the borehole must be monitored at all times. Excessive wear on the subsea equipment will result if the vessel is not aligned continuously over the hole. Two types of alignment indicators in common use are (1) tne

(Vtnts small quantity of mud to th« Annulus craoting o mud "Shock Wo».")

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