Surface and Subsurface Completion Equipment

Well completions involve placing flow control equipment at the surface and indie tubing string. These items may include the following major categories:

  • production tree
  • surface and subsurface automatic shutdown systems
  • flow string equipment
  • packers

The equipment must be sized and selected for each reservoir and its flow characteristics. The drilling plan should include a wellhead and geometry to accommodate this production equipment.

Production Tree. The production, or Christmas, tree provides the connection between the wellbore and the production equipment such as the separators and treatment facilities. The tree (Fig. 14-2) contains control valves and chokes. Many trees contain redundant equipment for safety purposes. Severe operating conditions such as hydrogen sulfide-produced fluids or Arctic and geothermal environments may require the use of modified wellheads.

The master valves, as the name implies, are the primary pressure control mechanisms in the tree. The valves may be manually operated and contain automatic shutdown equipment. Many trees have multiple valves.

The swab valve provides a means to access the tubing string for remedial work on the well. The valve can be closed so equipment such as wireline lubricators can be installed on the top of the tree. The valve is subsequently opened, and work can be initiated through the tree.

The tree alters the direction of the flowing fluid. The wing on the tree usually contains several types of safety valves and a choke. The wing may include an automatic safety valve. The choke is used to dissipate well pressure before the flowing fluid entering the low pressure, surface production equipment.

Automatic Shutdown Systems. On occasion, wells must be shutin to prevent an undesirable occurrence. For example, a ruptured flow line must be

Christmas Tree Drilling Engineering
Fig. 14-2 Christmas tree (Courtesy WKM Wellhead Equip.)

shutin to prevent a blowout. Shutin can be accomplished with surface or subsurface tools and can be controlled by direct- or remotc-controlled methods. These overall systems are generally termed automatic shutdown systems.

Surface Safety Equipment. Surface devices can cause the well to shutin automatically under abnormal operating conditions. Trigger conditions include high- or low-pressure fluctuations, fire, abnormal flow rates, and excessive erosion. Shutin can be through either direct- or remote-controlled operating systems.

Direct-controlled surface safety systems can be installed at any point downstream of the surface choke to sense line pressure changes at the point of valve installation only. Such safety valves are generally selected when automatic shutin protection is desired only for breaks in a flow line or sales line, cutting a surface choke by flow line pressure changes. These valves are self-contained and normally use a monitor-actuator pilot (Fig. 14-3).

A typical direct-controlled surface safety valve (Fig. 14^4) is a pilot-controlled safety valve, opened and closed by well or flow line pressure through a velocity check valve. Pressure within the valve, acting on the area of the stem against atmospheric pressure, causes the actuator to move the valve gate to its open position. The valve is designed to close automatically in the event of an abnormal change in flow line pressure. When the pilot senses a change beyond its setting, it actuates, exhausting the pressure from below the actuator piston and allowing the pressure above the piston to close the valve.

A remote-controlled surface safety system (Fig, 14-5) can be installed in the tree as a secondary master valve. It is usually a compact unit that can also be installed on wing valves upstream of the surface choke, header valves, flow lines, gathering lines, pipelines, or anywhere automatic valve shutin protection is desired. Monitor pilots, used with this valve, are located remotely at numerous high-risk areas throughout the system.

The surface systems are operated by a hydraulic control manifold designed to provide the hydraulic pressure required to hold open various valves and to control the pressure to the valves. Any loss of pressure in either the pilot line or hydraulic line closes the safety valve. Pressure loss could be from operating pilots or damage to the system (Fig. 14-6).

The operating principle for the control Manifold can he illustrated with Fig. 14-7. A gas-powered hydraulic pump is used to maintain a desired hydraulic pressure for the safety valve. When the monitor pilot in the safety system operates, it exhausts pressure from the low-pressure control line, causing the three-way valve in the control manifold to block incoming control pressure. This action in turn releases the control pressure of a diaphragm in the three-way hydraulic controller. On loss of control pressure, the controller blocks incoming hydraulic fluid pressure and allows the hydraulic fluid in the safety valve control line to bleed into the reservoir. The safety valve control line bleeds into the reservoir, causing the safety valve to close.

Self Contained Surface Safety Valve
Fig. 14-3 Direct-con trolled safety system (Courtesy Otis)
Surface Safety Valve Otis
Fig. 14-4 Pilot-controlled safety system (Courtesy Otis)
Pneumatic Internal Drilling Systems

type li otis pneumatic surface safetv valve

3-way block ano bleed valve

FUSIBLE PLUG

manual emergence shut-down valve type li otis pneumatic surface safetv valve

3-way block ano bleed valve

FUSIBLE PLUG

manual emergence shut-down valve

Fig. 14-5 Remote-controlled safety system (Courtesy Otis)

Subsurface Safety Valve
Fig. 14—6 Hydraulic control manifold fCourtesy Otis)
Otis Low High Pilot
Fig. 14-7 Control manifold operating principle (Courtesy Otis)

Monitor pilots control safety valves from remote points. Pilots are usually installed at one or more points downstream of the choke. Actuator pilots control the safety valve's opening/closing action but only on direction from a monitor pilot. Actuator pilots are mounted directly on the safety valve.

A typical combination high-low pressure-sensing device is shown in Fig. 14-8 and 14-9. The monitor pilot is a sensitive, liquid-filled gauge pilot designed to monitor pressure accurately through the use of a Bourdon lube. The pilot has higher pressure sensitivity and repeatability than conventional spring-actuated pilots. These pilots can monitor pressures from 40-20,000 psi.

An erosion pilot is used where internal erosion is most likely to occur. The pilot is equipped with a hollow probe that protrudes into the flow stream. The housing of the pilot is cylindrical, it is pointed to provide a means of connecting the safety system control lines. The pilot operates only after erosion penetrates the thin wall of the probe. Pressure within the vessel acts against the lower end of the piston and forces the piston and plunger upward until the valve containing the system control pressure is opened. The system control pressure

Plunger Lift Wing Valve Control Diagram

Fig, 14-8 Placement of high-low sensing device (Courtesy Otis)

exhausts to the atmosphere around the plunger, activating the safety system (Fig. 14-10).

Fusible plugs can sense high temperatures as in the ease of fire (Fig. 14— I I). The fusible material will melt in the event of dangerously high temperatures. This action causes the control line pressure to be exhausted from the safety valve chamber, thereby letting the valve close. It is recommended that these plugs be considered for use in all safety installations.

An activator pilot (Fig. 14-12) can be installed where it is desired to control a safety valve from a remote, high-pressure source. The high control line pressure enters the pilot and the monitor-actuator pilots, which monitor either high- or low-pressure liuctuation in the flow line. It employs a piston for operation. The piston area is several times larger than the ball seat, and pressure on the piston offsets a higher pressure acting on the bail. When pressure within the pilot chamber varies beyond the limits of the companion high- or low-pressure pilots, one or both of the pilots exhaust the chamber pressure, forcing the valve to close.

Subsurface Safety Equipment. Subsurface safety devices shutin a well automatically in the event of undesirable occurrences. These devices may be direct or surface controlled and can be flapper or ball systems.

Otis Sub Surface Ball Valve

In Service

LOW PRESSURE ADJUSTING SCREW

LOW PRESSURE ADJUSTING SCREW

Surface Safety Valve Tree Pneumatic

INDICATOR PIN

HIGH PRESSURE

ADJUSTING

SCREW

TOGGLE VALVE UNSEATED BY MOVEMENT OF SENSING PLUNGER

Operated

INDICATOR PIN

HIGH PRESSURE

ADJUSTING

SCREW

TOGGLE VALVE UNSEATED BY MOVEMENT OF SENSING PLUNGER

In Service

Operated

Fig. 14-9 Operation of high-low device (Courtesy Otis)

Toggle Valve
Fig. 14-10 Erosion pilot (Courtesy Otis)

Fig. 14-11 Fusible plug (Courtesy Otis)

The surface-controlled automatic shutin surface/subsurface safety system (Fig. 14-13) uses a pneumatic line to control the wing valve on the tree. A hydraulic system controls the secondary master valves and the tubing safety valve. The system is designed to shutin surface and subsurface safely valves automatically in the event of abnormally high or low line pressure, explosion, or fires.

0-R!NG QUICK UNION

0-R!NG QUICK UNION

Way Toggle Valve
Operated

Fig. 14-12 Type M Otis actuator pilot (Courtesy Otis)

A typical surface-controlled, wireline-retrievable safety valve is shown in Fig. 34-14. The normally closed valve is held open by hydraulic pressure through an external control line or through the casing-tubing annulus in concentric installations. Upon loss of the hydraulic pressure, the large valve spring will lift the hydraulic head of the control fluid and rotate the ball into a closed position. When setting a valve deeper, additional spring modules can be added to offset the increased weight of the hydraulic control fluid.

The hydraulic control line is normally run with the tubing into the well. The control line is connected to the tubing with metal bands (Fig. 14-15). Table 14-1 lists dimensions for several types of control lines.

tvpe u otis pneumatic i i surface safetv valves,j- ■ h type u otis hydraulic to other blow-down valve wells type u otis hydraulic to other blow-down valve wells

Otis Choke Valve

hemote-cowtrolled^ subsurface safety valves

Fig. 14-13 Automatic surface/subsurface safety system (Courtesy Otis)

hemote-cowtrolled^ subsurface safety valves

CD CD m

Fig. 14-13 Automatic surface/subsurface safety system (Courtesy Otis)

Downhole Safety Valve Hydraulic

Schematic 1 Schematic 2 Schematic 3

Equalizing Open Closed

Schematic 1 Schematic 2 Schematic 3

Equalizing Open Closed

£3 HYDRAULIC PRESSURE ■ WELL PRESSURE

Fig. 14-14 Surface-controlled, wireldS^retrievable safety valve (Courtesy Otis)

Direct-control led subsurface safety systems are generally the same type. These function due to either abnormal flow rates, differential pressure, or loss of pressure. In many cases, surface-controlled valves might be preferred. Direct-controlled tubing safety valves close on predetermined conditions, and they do not offer protection until these conditions exist. The direct-control led safety valve (Fig. 14-16) is normally an open valve that operates on a spring-loaded, flow bean, pressure differential principle. The valve has a flow skirt that extends below the valve to protect the tubing wall from turbulence at that point. The spring holds the valve offset until the well flow reaches a predetermined rate. When the pressure differential across the bean exceeds the spring tension, the valve is designed to close, shutting in the well below

Double Control Line Installations

Double Control Line Installations

Cable Installations

Cable Installations

Fig. 14-15 Control lines and metal bands (Courtesy Otis)

Table 14-1 Hydraulic Control Lines

Type

Description

OD, in.

ID, in.

A

'/s-in. line pipe, 0.095-in, wall, schedule 80,

0.405

0.215

grade B

B

'/i-in. tubing, 0.049-in, wall, annealed carbon

0.250

0.152

steel

C

'/t-in. tubing, 0,049-in. wall, seamless stain

0.250

0,152

less steel (304L)

D

'/i-in. tubing, 0.049-in. wall, welded and

0.250

0.152

drawn stainless steel (304L)

E

'/i-in, tubing, 0.045-in. wall, annealed moncl

0.250

0.160

(400)

F

1-in. x 0.44-in. dual polyester encapsulated

0.250

0.152

  1. 049-in. wall tubing with stainless steel tracer cable
  2. 049-in. wall tubing with stainless steel tracer cable the earth's surface. To reopen, pressure must be applied in the tubing from the surface or by an equalizing prong. When pressure is equalized, the spring opens the valve automatically.

The term storm choke is commonly used to describe all direct-controlled subsurface safety valves. Storm Choke® is a registered trademark for a popular brand manufactured by Otis.

Ambient tubing safety valves (Fig. 14-17) are precharged with a set dome pressure. When the well is flowing and pressure drops below the predetermined dome-pressure charge, the dome pressure and valve spring close the valve, shutting in the well below the surface.

Flow String System. Flow string systems are the components used in the tubing string to conduct produced fluids from the reservoir to the surface. They include tubing, mandrels and nipples, flow couplings, blast joints, sliding sleeves, and back-pressure valves. Tubing and couplings are usually designed before the workover is initiated and therefore become only a matter of routine running procedures.

Back-Pressure Valves. Prior to initiating workover, a mechanical-set, backpressure vaive is often installed in the top of the tubing at the bottom of the production tree. Wireline-set plugs are also available. The plug can be a oneway valve that allows flow only from the tree into the tubing or from the tubing into the tree. It may be a solid plug that prevents flow in any direction. The solid plug is often used because it will seal off well flow and allow pressure testing of the tree or new equipment. In producing wells, the valve may be set

Slickline Pneumatic Pulling Tools

SPACER WASHER

VAIVE CAGE

BEAN EXTENSION

VALVE SEAT

OPEN

CLOSED

SPACER WASHER

VAIVE CAGE

BEAN EXTENSION

VALVE SEAT

OPEN

CLOSED

  1. 14-16 Direct-con trolled safety valve (Courtesy Otis)
  2. up ring o-sing guide ping

PISTON SPRING CHAMBER

SCREW GASKET

back-up ring q-king

BODY WEIDMENT

BALI AND Si AT

back. up ring o-sing guide ping

PISTON SPRING CHAMBER

SCREW GASKET

back-up ring q-king

OPEN

I WELL

PRESSURE

CLOSED

I INTERNAL CHAMBER

PRESSURE

BODY WEIDMENT

BALI AND Si AT

Fig. 14-17 Ambient tubing safety valve (Courtesy Otis)

with a lubricator at Ihe top of the tree. The valve in Fig. 14-18 seals well pressure from the tree but allows pumping into the well.

Mandrels and Nipples. Wireline-set mandrels are often used as a primary means of controlling flow in the tubing string. These mandrels, depending upon type selection, may perform such functions as blocking flow either up or down in the tubing or in both directions, providing a choking effect to minimize surface pressure, gas-lifting oil wells, and serving as a surface-controlled subsurface valve. The mandrels are used with specific nipples designed to latch and hold the device. Numerous types of nipples and mandrels are shown in Fig. 14-19.

Equalizing subs are used where pressure differentials are anticipated across a flow-control device if the device does not include such provisions. They are generally used with large-bore mandrels. The operational mechanics of the equalizing sub are shown in Fig. 14-20. The equalizing sub is in its open position when run. The running prong shifts the sleeve to a closed position after setting. Pulling the prong shifts the sleeve downward to its open position.

Flow Couplings. Landing nipples are generally not the same ID as the tubing string. As a result, the diameter change will cause increased turbulence in the (lowing fluid at this point. This turbulence will dramatically increase erosion rate of the tubing, causing possible early failure. Flow couplings minimize these failures.

Maximum OD thread

Seal ring

Body

Spring

Valve

Valve stem

Maximum OD thread

Seal ring

Body

Spring

Valve

Valve stem

Fig. 14-18 Mechanical-set back pressure valve (Courtesy Otis}

A flow coupling (Fig, 14-21) is a thick-walled section of tubing installed above, and often below, the diameter change. Field experience indicates that flow couplings should be 36 in. or longer for maximum protection. Many manufacturers produce the couplings in 5-, 10-, or 20-ft lengths.

Blast J aims. Blast joints are used in the tubing string to protect against external erosion, as in the case of dual-completion wells (Figs, 14-22 and 14-23), Most are special alloy, heat-treated joints and are available in 10- and 20-ft lengths. Blast joint connections generally make up flush.

Sliding Sleeves. Selective circulating devices, such as a sliding sleeve, provide openings between the tubing and the annulus without the necessity of perforating. The tool is useful when circulating fluids for well control or producing from other intervals (Figs. 14—23 and 14-24). Problems are often associated with the tool, however, when attempting to use it after an extended time in the tubing.

Packers, The annular seal between the tubing and production casing is provided by the packer. It must be able to withstand high differential pressure and still maintain a seal. Tubing movement must be considered when temperatures change (Chapter 13). In addition, corrosive fluids such as hydrogen sulfide (H,S) must be resisted.

General packer classifications are retrievable and permanent. The permanent type is held in place by opposing slips and can be set with wireline or tubing-conveyed methods. The retrievable packers can be weight set. mechanical set, or hydraulic set.

Packers generally can be divided into four major components, including slip assembly, outer seal assembly, packer bore receptacle, and tubing seal assembly. The slip assembly and outer seal secure and seal the packer-casing interface. The packer bore and the tubing seal assembly provide the tubing-packer pressure seal while allowing tubing expansion or contraction to occur (Figs. 14-25 and 13-1).

Rubber elements with varying hardness and composition are used to provide the pressure seal for the outer seal assembly and the tubing seal assembly. The most commonly used rubber is nitrile. with a 70-durometer hardness. High bottom-hole temperatures require a greater hardness (80-90).

Corrosive gases such as hydrogen sulfide will crack the rubber elements if nitrile is used. Serviceable elements such as Viton® (DuPont) can be effectively used in H,S environments with little or no cmbrittlemeni tendencies. If amino-based corrosion inhibitors are used, however, the Viton® will deteriorate because of fluorocarbon composition in the inhibitor. As a result, sealing elements exposed to amine inhibitors require alternative rubber compounds such as K-Ryte® (Baker). This rubber is a layered structure composed of Kalre?®, Teflon®, and Rylon®. These rubbers are generally used only when necessary bccause they may cost 100 times more than nitrile.

Otis Nipples Wireline
Fig. 14-19 Nipples and mandrels (Courtesy Otis)
Oil Well Packer Mandrel

Fig. 14-20 Equalizing sub (Courtesy Otis)

Flow Coupling

FLOW

COUPLING

(Optional)

FLOW

COUPLING

(Optional)

Fig. 14-21 Flow coupling (Courtesy Otis)

Oil Flow Coupling

FLOW COUPLING LANDING NIPPLE FLOW COUPLING

CIRCULATING DEVICE

PRODUCTION PACKER CIRCULATING DEVICE

FtOW COUPLING LANDING NIPPLE BLAST JOINT LANDING NIPPLE

FLOW COUPLING LANDING NIPPLE FLOW COUPLING

CIRCULATING DEVICE

PRODUCTION PACKER CIRCULATING DEVICE

FtOW COUPLING LANDING NIPPLE BLAST JOINT LANDING NIPPLE

Drill Pipe Nipple

PRODUCTION PACKER NO-GO NIPPLE

PRODUCTION PACKER

CIRCULATING DEVICE

FLOW COUPLING LANDING NIPPLE BLAST JOINT LANDING NIPPLE

PRODUCTION PACKER NO-GO NIPPLE

PRODUCTION PACKER

CIRCULATING DEVICE

FLOW COUPLING LANDING NIPPLE BLAST JOINT LANDING NIPPLE

Fig. 14-23 Blast joint placement (Courtesy Otis)

LANDING

NIPPLE

PROFILE

PACK-OFF

SEALING

AREA

Type XO Otis

Sliding Side-Door

INNER SLEEVE

THREE-STAGE COLLET LOCK

LOCK RECESS (EQUALIZING POSITION)

LOCK RECESS

(OPEN

POSITION)

POLISHED ■SEALING AREA

Sc/je ma tic 1

Type XO Otis Sliding Side-Door (Closed)

  • LOWER ZONE
  • UPPER ZONE

Schematic 2

Type XO Otis Sliding Side-Door in open position with separation toolmplace.

Type XO Otis

Sliding Side-Door

Fig. 14-24 Sliding sleeve (Courtesy Otis)

Baker New Packer
Fig. 14-25 Packer assembly (Courtesy Baker Packers)

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Responses

  • arto
    What does sub surface tools do?
    8 years ago
  • ELIZABETH
    How to select material and threadings for Flow control equipments in oil wells?
    8 years ago
  • primula rumble
    What is bleed valve on x mass tree on oil well?
    7 years ago
  • lucas
    Does otis type XA sliding sleeve open up or down?
    7 years ago
  • terhi
    What is a wing valve on a christmas tree?
    7 years ago
  • Arcangelo
    What is subsurface completion equipment?
    7 years ago
  • Herman
    What is surface safety valve function?
    7 years ago
  • Futsum
    What is a hydraulic choke?
    6 years ago
  • KIMI
    Are flowlines subsurface equipment?
    5 years ago
  • GOYTIOM
    Are chokes subsurface or surface?
    5 years ago
  • luisella
    What are subsurface equipments used in drilling oil?
    4 years ago
  • Arnor
    What are wireline subsurface equipments?
    3 years ago
  • declan
    Where is erosion nipples on hydraulic choke valve?
    2 years ago
  • marco
    What are the equipment list required for oiwell completion?
    2 years ago
  • senay
    How to trip surface safety valve otis?
    1 year ago
  • marco tunnelly
    IS A PLUNGER SURFACE OR SUBSURFACE EQUIPMENT?
    10 months ago
  • merimas
    What are well completion equipmentn?
    2 months ago

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