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1. STATE UNIVERSITY OF
CAMPINAS
COMPLETION EQUIPMENT
FRANCISCO MBATCHI

2. TREE AND TUBING HANGER
The purposes of the Christmas tree are to
􏰂 Provide the primary method of closing in a well;
􏰂 Isolate the well from adjacent wells;
􏰂 Connect a flowline;
􏰂 Provide vertical access for well interventions (slickline, electricline, coiled tubing,etc.)
whilst the well is live;
􏰂 Interface with the tubing hanger;
􏰂 Connect or interface the tree to the wellhead.

3. Conventional (vertical) and horizontal trees
The difference between the vertical and horizontal tree
is in the position of the valves. In a vertical tree, the
master valves are in the vertical position and inline
with the tubing, whilst in a horizontal tree, they are
horizontal and away from the production/casing bore.
Subsea horizontal trees therefore usually require a
subsea test tree for installation activities such as clean-
up flows and through-tubing interventions. This
difficulty restricts the application of horizontal trees in
land and platform wells.

4. Sequencing of tree installation (vertical vs. horizontal trees)

5. PLATFORM AND LAND CHRISTMAS TREES
In figure, the hanger is secured with lock-down bolts
and with a spool installed once the hanger has been
landed and the BOP removed. Without a lock-down
feature of some sort, thermal expansion or high-
annular pressures may overcome tubing weight and
push the tubing hanger off the seal. The landing string
for the tubing hanger can be identical to the tubing.
Alternatively and more commonly, slightly larger tubing
can be used to allow the deployment of tubing hanger
plugs that cannot fit inside the tubing.

6. The tubing hanger usually incorporates a profile
for the setting of plugs or back pressure valves.
These isolation devices are drillpipe, rod or
wireline set. The figure shows a platform well with
the tubing hanger evident. An isolation plug is
inside the hanger. Any debris falling onto the plug
when the BOP is removed can easily be scooped
out by hand or jetted clean.
PLATFORM AND LAND CHRISTMAS TREES

7. Any debris falling onto the plug when the BOP is removed
can easily be scooped out by hand or jetted clean. Note the
four control lines protruding through the tubing hanger in
Figure. Three of these control lines (currently capped) are
for operating sliding sleeves. The fourth (with temporary
test line) connects to the downhole safety valve. Control
lines (and gauges) can screw onto the base of the tubing
hanger with a further connection on the top. The
configuration shown in Figure has the control lines
continuous through the tubing hanger with a single
connection between the control line and the tubing hanger.
PLATFORM AND LAND CHRISTMAS TREES

8. PLATFORM AND LAND CHRISTMAS
TREES
Christmas tree with dual flowlines (for
increased flow capacity). The tree contains
two manual master valves. There are both
manual and hydraulic wing valves on each
side.
Many land wells use separate spools for
each valve. This makes valve replacement
easier, but increases the size (and weight) of
the tree.

9. SUBSEA CHRISTMAS TREES
The horizontal subsea tree
requires a single-bore riser.
Annulus fluids can be bled off
through a concentric port in the
tubing hanger and then through
an annular master valve on the
side of the tree. No plugs are
required on the annulus flow
path.
Horizontal subsea tree with tubing hanger Horizontal subsea tree

10. SUBSEA CHRISTMAS TREES
The tubing head seals to the wellhead, making it easier to fix problems
with this seal, rather than pulling an entire tree back to surface. The
tubing head then provides the orientation mechanism for the tree. A
further improvement is an ROV-operable annulus isolation valve. This
avoids having to run a dual-bore running string/riser as plugs are no
longer required on the annulus side. The drawing also shows a modified
tree cap that can be run by an ROV. The tree cap is modified for the
enhanced horizontal tree and now sits inside the tree. The isolation plug
above the tubing hanger has been replaced with a second plug inside the
tubing hanger. This improves debris resistance and simplifies operations.

11. SUBSURFACE SAFETY VALVES
Subsurface safety valves are fail-safe valves that are designed to prevent an uncontrolled release of hydrocarbons
from the well if something catastrophic occurs at surface. Events that could lead to the required closure of a
downhole safety valve include:
 A major platform incident such as an explosion or hurricane that could cripple a Christmas tree.
An impact with the tree, for example, a heavy truck colliding with a land well, a dropped BOP or a submarine
colliding with a subsea tree.
 Loss of integrity of the tree through structural failure, corrosion, fatigue, improper use, incorrect design or
installation or poor maintenance.
 Terrorist or act of war, for example, invasion and deliberate torching of Kuwaiti wells.

12. HYDRAULIC CONSIDERATIONS
Most modern completions use tubing
retrievable safety valves, except where
conditions and rates are benign. These valves
are more reliable than wireline retrievable
versions, provide fewer restrictions and do not
need to be pulled for every well intervention.
A typical configuration of a tubing retrievable
downhole safety valve is shown in Figure. Tubing retrievable downhole safety valve

13. HYDRAULIC CONSIDERATIONS
Some older designs use ball valves instead of
flappers, but the simplicity of flapper systems
means that ball valve designs are now rare (they
are still used in deployment valves where being
able to pressure test from above is useful). Almost
all flapper valves are pump through which is useful
if the valve fails and a hydraulic kill is required.
A wireline retrievable downhole safety valve is
shown in Figure.

14. HYDRAULIC CONSIDERATIONS
Hydraulic pressure from the control line acts on a piston.
This piston is then connected to the flow tube. Figure shows
the detail of a single rod piston with the cylinder removed.
This piston has ‘T’ seals and a stop seal. The point of
connection to the flow tube is on the right-hand side of the
photo. Hydraulic pressure comes from a combination
of applied surface pressure and hydrostatic pressure
of the control line (or annulus) fluid. If the valve is
positioned too deep, the hydrostatic pressure can
maintain the valve open even when all surface
pressure has been bled off. The maximum fail close
setting depth (Dmax) is given by Eq.

15. PACKERS
Packers provide a structural purpose (anchor the tubing to casing) and a sealing purpose.
They are used in a variety of applications:
􏰂 Isolate the annulus to provide sufficient barriers or casing corrosion prevention (production
packer).
􏰂 Isolate different production zones for zonal isolation (e.g. downhole flow control wells).
􏰂 Isolate gravel and sand (gravel pack packer and sump packer).
􏰂 Provide an annular seal in conjunction with an ASV.
􏰂 Provide a repair or isolation capability (e.g. straddle packers).

17. PRODUCTION PACKER TAILPIPES
This design allows a plug to be set below the packer for
contingent tophole workovers. If the deep-set plug cannot be
retrieved at the end of the workover (e.g. debris on top of the
plug), the tailpipe can be punched. All components should be
spaced out to aid in wireline depth control and provide
contingencies. The fluted centraliser is designed to no-go on
the top of the liner, without damaging either. For platform and
land wells this aids in space-out. For subsea applications
(especially deepwater), the centraliser is often shearable with several
joints of flush joint tubing above – over a which it can travel. This
provides positive indication of the tailpipe position without requiring
either undue accuracy or pulling back the tubing.

18. LANDING NIPPLES, LOCKS AND SLEEVES
A number of proprietary systems are available for the locking and sealing of wireline (occasionally coiled tubing)
deployed tools into the completion. The applications include:
 Plugs for pressure testing, isolation and well suspension (e.g. removal of the BOP).
􏰂 Check valves (standing valves) for pressure testing.
􏰂 Deployment of memory (or wireless telemetry) gauges for pressure build-up (PBU) analysis.
􏰂 Being able to move sliding sleeves [sliding side doors (SSDs)].
􏰂 Deployment of downhole chokes.
􏰂 Landing of siphon or velocity strings.
􏰂 Positioning of storm chokes or the inset of a wireline retrievable valve.

19. LANDING NIPPLES, LOCKS AND SLEEVES
There are two methods of landing such devices:
 Running a lock into a nipple profile pre-installed in the completion. Attached to the lock will be
a blanking plug, standing valve, gauge, etc.
􏰂 Using a wireline (slickline or electricline) deployed packer ( bridge plug ) that can be set
anywhere in the tubing. Attached to the packer is a plug, standing valve, gauge, etc.

20. The position of the seal bore, profile and no-go varies between different
suppliers, thus making most locks non-interchangeable. The primary purpose of
the no-go is for positive depth control. In some locks, downward forces (e.g.
during a pressure test from above) are taken through the no-go; but with a well-
designed modern lock mechanism this is not necessary. Where the load is
taken on the locking dogs, pressure should not be used to help the lock into the
nipple profile – the no-go is for location only and is not load bearing. Having a
no-go requires that nipple profiles progressively reduce in internal diameter with
increasing depth. This can be restrictive to tools that are run through the upper
completion and into the reservoir completion (e.g. for zonal isolation). However, these
reducing diameters have the advantage that seals do not need to be ‘tapped’ through
seal bores on their way to deeper locations.
LANDING NIPPLES, LOCKS AND SLEEVES

21. Figure. Potential nipple locations

22. REFERENCES
Aasen, J. A. and Aadnøy, B. S., 2002. Buckling Models Revisited. SPE 77245.
Adams, A. J., Moore, P. W., Prideco, G., et al., 2001. On the Calibration of Design Collapse
Strengths for
Quenched and Tempered Pipe. OTC 13048.
API Bulletin 5C2, 1999. Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe, 21st
ed.
American Petroleum Institute, Washington, USA.
API Bulletin 5C3, 1994, with supplement 1999. Bulletin on Formulas and Calculations for Casing,
Tubing,
Drill Pipe, and Line Pipe Properties. 6th ed. American Petroleum Institute, Washington, USA. API
RP 37, 1980. Recommended Practice Proof – Test Procedures for Evaluation of High-Pressure
Casing and

23. Thank you for your
kind attention