4. Nipple Profiles/Lock Mandrels
Selective No-Go Monobore
Completions Completions Completions
X® RPT, RQ Monolock®
STD Weight FC - SSSV, Plug, FC - Plug, Choke,
Choke, Gauge Gauge
FC - SSSV, Plug,
Choke, Gauge FBN®
SafetySet®
SSSV Full Bore,
R® Special Applications Monobore
Heavy Weight High Pressure and Completions
FC - SSSV, Plug, Flow Rate FC - Plug, Choke
Choke, Gauge
SRP
Wellhead Plugs
4
5. X® & R® Selective Landing Nipple/Locking Mandrel System
Design Benefits
Nipples installed in tubing string in any order- reducing workover risk
Provides unlimited number of positions to set
Running tool allows selection of nipple to land and set the lock
Same ID in all nipples reducing flowing pressure loss and minimizing
turbulence
Maximum flow capacity from large, straight-through bore of locking
mandrel
OTIS® X® Maximum versatility reducing completion and production
Locking OTIS X® maintenance costs
Mandrel Landing
Nipple Allows for repositioning of flow controls as well conditions change
Keys of locking mandrel retracted into assembly while running and
retrieving 5
6. Otis® RPT® No-Go Type Nipple and Lock Mandrel
• Provides a means of running a series of positive location landing
nipples in a tubing string with minimum restriction
• Locates on top of the polished bore of the nipple
• No secondary restrictions normally associated with bottom no-go
profiles
• Provides positive location of the lock and minimizes the possibility
of misruns
Applications
High-pressure, high temperature, large bore completions
For running a series of nipples in a tubing string when positive
location and minimal ID reduction are required
Features
Large bore
Lock mandrel no-go locates on top of the nipples’ polished bore
Benefits
RPT® Lock with
Equalizing Valve and
No secondary restrictions normally associated with bottom no- Cap installed in RPT
go profiles Nipple
Lock mandrels in a particular size range use the same running
and pulling tools 6
8. Mirage® Disappearing Plug
Applications in -
• Horizontal wells where plug installation
after completion is undesirable
• Setting production and isolation
packers
• Testing tubing
• Wells where slickline or CTU
intervention after completion is
undesirable
8
9. Mirage® Disappearing Plug and Autofill Device
How it
Hydraulic-Set Packer Autofill Device Multi-cycle Mirage® Plug
works:
1. Autofill and Mirage plug are run to depth below a
hydraulic set packer. The tubing is filled through the
Autofill when running downhole.
2. Multiple pressure cycles against the Mirage plug
allows closure of Autofill, tubing test and setting of
packer.
3. Final pressure cycle dissolves Mirage plug matrix
for full bore access. 9
10. Monolock® Plug
Applications
• Retrievable bridge plug
• Can be adapted to install BHP gauges and other
flow control devices
• Plug tubing below hanger for wellhead repairs
Available in
3-1/2” thru 7”
Pressure rating base or 70% of pipe yield or
maximum of 10,000 psi
10
11. Benefits of Design
• Requires no landing nipple for broader
applications
• Seals against pipe ID which can eliminate
restrictive sealing bores in tubing string
• Retained in set position by internal slips
providing same reliability as production packers
• Can use slickline rather than conductor line
lowering installation and retrieval costs
11
12. Benefits of Design
Can be installed and retrieved through restrictions
Plug is run in closed position increasing reliability
Can be run with DPU®, Baker setting tool, or
hydraulic setting tool
Run on slickline, braided line, coiled tubing, or
electric line
Soft set for sensitive equipment
12
14. DuraSleeve® Non-Elastomer
Circulation / Production Sleeve
Applications in -
TOP SUB WITH
LANDING NIPPLE
Producing alternate zone in single-
PROFILE selective completions
Circulating kill fluid eliminates expense
of perforating tubing
Secondary recovery
CLOSING SLEEVE
Washing above packer
NON-ELASTOMER
NON-
SEALS Design Capability-
LARGE FLOW
PORTS Sizes for 1 1/2” to 7” production tubing
EQUALIZING PORTS
Pressure ratings equal to tubing
ratings
Open-up and open-down options
BOTTOM SUB
WITH POLISHED BORE A variety of materials and thread
END SUB options
14
15. Shifting Force of DURATEF™ ECM Seals
Designing sleeves to shift after years of production
Nitrile Seal* PEEK Seal ECM
3000 lbs
2500 lbs
2000 lbs
1500 lbs
1000 lbs
500 lbs
0 lbs
* The Engineering T est Lab used the nitrile seal as a benchmark to compare the PEEK seal and the engineered composite seal.
Shifting forces for Nitrile Seal, PEEK seal, and the DURATEF™ ECM seal
Shifting forces for DuraSleeve® sliding sleeve are less
than 1/5 the force required for sleeves with competitive
materials such as PEEK
15
16. Slimline Sliding Side-Door® Device
• Small OD SSD designed for concentric string
gravel pack completions
• Allows for running larger size tubing inside
small ID casing
2 3/8” – 2.72 v. 3.25 OD
2 7/8” – 3.22 v. 3.92 OD
3 1/2” - 3.92 v. 4.50 OD
• OD’s comparable to CS Hydril upset
• 5000 psi rating (more with material upgrade)
• Tensile rating 60-70% of N-80 tubing
• Standard B shifting tool
16
17. SSD Variations
Surface controlled by control line
Pressure close/auto open device
Setting depth sensitive
Pressure activated (HASSD)
Run closed
Pressure tubing over annulus to activate
Opens on bleed down
17
19. SRP Wellhead Plugs
• Deepwater development has created
demand for wellhead plugs
• Used primarily in subsea trees
• Ultra-compact design allows for use in
horizontal trees
• Available in equalizing and non-
equalizing models
• High-pressure rating above and below
• No-go design with minimum restriction
19
20. SRP Wellhead Plug
Design Features-
Compact length reduces space requirements of wellhead
Single leak path is through two full packing stacks
High pressure rating from above and below
Multiple shear pin hold down mechanisms for redundancy
Simple design for high reliability. Only two moving parts: keys
and expander sleeve
20
21. SRP wellhead with added back pressure
valve
Equalizing plug w/ M-T-M
Redundant seal stacks seal plus redundant seal
Back pressure valve
uses M-T-M seal with
redundant seal stack
Hold-down pins engage
expander mandrel after set
21
22. SRP Wellhead Back Pressure Valve
Design Features-
Redundant seals along all leak paths
OD leak path is through two full packing stacks
Equalizing plug leak path is through a static MTM seal and an O-ring
Valve leak path is through a MTM seal and a packing stack
Multiple shear pin hold down mechanisms for redundancy
Only three moving parts: keys, expander sleeve, and valve
Can hold pressure from above with the addition of a test prong
Cannot be pulled until equalized
Two options for equalizing prongs. One engages the knock-out plug and one
pushes the dart off seat
22
23. SRP Wellhead Back Pressure
Valve
Optional test prong isolates the back
pressure valve to allow pressure testing
of SRP plug from above
23
24. SSP Wellhead Plug
• MTM seal plus a single packing stack,
compatible with FMC wellhead First Fishneck
• Compact length Third Fishneck
• Test pressures up to 15,000 psi Expander Sleeve
• PR-2 and vibration tested
Second Fishneck
• Static after set
– Hydrostatic running tool applies Debris Barriers
predetermined force into expander
sleeve taper 3° Taper
– 3 degree taper statically sets key
into profile for no plug movement
• Secondary interference locking sleeve
• Large throw keys
MTM Seal
• Three fishnecks
– Two fishnecks on expander sleeve Interference Sleeve for
– Additional fishneck on plug body Secondary Hold Down
24
25. Wellhead Isolation Sleeve
Applications
• Used to isolate flow wing valves during
tree testing and handling
Features
• Interference “hold down” mechanism
• Run and pulled using conventional
wireline methods
• Debris barrier
• Run and retrieved ssing the same tool
25
27. Flow Couplings
Flow couplings in the tubing are an important part of life-of-the-well
completion planning. Flow couplings have a wall thickness greater
than the corresponding tubing to inhibit erosion caused by flow
turbulence. Flow couplings should be installed above and below
landing nipples or other restrictions that may cause turbulent flow.
Applications
To help inhibit erosion caused by flow turbulence
Installed above and below landing nipples, tubing
retrievable safety valves, or any other restriction that may
cause turbulent flow
Benefits
Helps extend the life of the well completion
27
28. Blast Joints
Blast joints are installed in the tubing opposite
perforations in wells with two or more zones. The
blast joints are heavy walled and are sized to help
prevent tubing damage from the jetting action of the
zone perforations. Blast joints should be installed
above and below landing nipples or other restrictions
that may cause turbulent flow.
Applications
To help inhibit erosion caused by jetting action
near perforations
Installed opposite perforations in one or more
zones
Benefits
Helps extend the life of the well completion
28
