Originally appeared in World Oil® AUGUST 2014 issue, pgs 43-50. Posted with permission.

1. Originally appeared in World Oil® AUGUST 2014 issue, pgs 43-50. Posted with permission.
SPECIAL FOCUS: OIL COUNTRY TUBULAR GOODS
Expandable liner hanger and packer exceed
expectations for first deepwater well in Red Sea
World Oil® / AUGUST 2014 43
A newly developed,
11¾-in., expandable liner
hanger packer (ELHP) system
made it possible to overcome
the challenges of drilling Saudi
Aramco’s first deepwater well,
a rank wildcat in the Red Sea.
ŝŝOPEYEMI ADEWUYA, SHRIKANT TIWARI,
Saudi Aramco; and ABDULLAH O. ABDELWAHED
and MAURILIO SOLANO, Baker Hughes
When a wildcat is drilled in deep water,
the challenge is magnified by the distor-tion
and unpredictability of geopressure
and temperature gradients produced by
the presence of salt diapirs, and stressed
pre- and post-salt formation layers. So,
when Saudi Aramco drilled its first well
in the Red Sea, a rank wildcat deepwater
well, it was with the knowledge that the
The 113/4-in. ELHP was deployed successfully
after a short design and development cycle.
well and casing designs would need to be
robust enough to withstand all drilling and
production loads, yet be flexible enough to
accommodate possible variations. Many of
the variations were unknown, because of
the nature of the well, and the fact that it
was the first in the deepwater Red Sea.
The decision to work with Baker
Hughes, to develop and deploy an 11¾-in.
version of the TORXS ELHP, was based on
the expectation that, to reach the proposed
bottomhole depth, the wellpath would
need to traverse a massive salt section, sub-tended
by an unknown length of rubble
zone. The ELHP was designed to meet and
exceed requirements for this application.
PROJECT BACKGROUND
The Red Sea, which separates Saudi
Arabia from Africa, is a fault depression
that traverses 1,300 mi, from Suez in the
north to the Bab el-Mandeb strait in the
south, where it connects to the Gulf of
Aden, and then to the Arabian Sea. The
deepest waters are over 6,000 ft, and the
seabed is rugged. Saudi Aramco drilled
its first exploration well at a 2,100-ft water
depth, approximately 48 mi off the west
coast of the Kingdom.
TECHNICAL CHALLENGES
Because the well was a rank wildcat, off-set
well information was nonexistent, and
data from shelf wells drilled in the 1960s
were insufficient for informed decision-making
on temperature and pressure re-gimes.
Formation tops and pressure pre-dictions
were based on a pre-drill analysis,
carried out on the basis of 3D seismic sur-veys.
The presence of a massive Mansiyah
evaporite salt bed was expected. Seabed
geophysical analysis, 3D wide-azimuth
seismic, and high-definition bathymetric
surveys predicted several scenarios, that
indicated a very soft seabed, varying esti-mates
of the top and base of the salt layer,
and different pressure trends, depending
on the formation sequence below the salt.
The project team was confident about
the post-salt formation tops and salt thick-ness
and, as a result, developed a success-ful
well design and drilling strategy to the
base of the salt layer. However, the pre-salt
environment was less discernible. It is be-

2. 60 70 80 90 100 110 120 130 140 150
low the salt that the thin margin between
pore pressure (PP) and fracture gradient
(FG) occurs. The mud density exerts hy-drostatic
equivalent to the drilling fluid
column back to the rig. FG, which results
from the overburden of sediments, starts to
build, only below the seabed. Because salt
has a high FG, it can be drilled with higher
mud weight to handle possible creeping or
inclusions. This geopressure continuum
reverses in the rubble zone. Here, a lower
FG is accompanied by high levels of losses.
According to the Red Sea geological col-umn
series, the Mansiyah salt is subtended
by multilayered anhydrite-shale-anhydrite
beds. This bedding sequence distorts nor-mal
geopressure trends. Correspondingly,
PP-FG prediction and mud weight (MW)
selection for the exploration well would re-quire
astute analytical and predictive geo-physical
insights ahead of the bit, Fig. 1.
To address the additional challenge of
poor imaging and velocity contrast at the
base of the salt layer, high-resolution verti-cal
seismic profiling (VSP) surveys were
acquired. The high-resolution VSP data
were inverted for acoustic impedance; the
acoustic impedance profile was converted
to interval velocities; and, subsequently,
the formation velocity profile was trans-formed
to a PP prediction and minimum
MW recommendation.
The predictive utility and workflow
of incorporating pressure sampling from
a quad combo logging-while-drilling
(LWD) tool, and VSP inversion for MW
prediction and lithostratigraphic delinea-tion
44 AUGUST 2014 / WorldOil.com
20 in.
were explored. The combination of
VSP inversion and formation pressure tes-ter
(FPT) pressure test points was highly
instrumental in picking the PP regression.
With some precision and operational pa-rameters,
MW and projections to the PP-FG
trend were adjusted on a timely basis,
and as appropriate.
Drilling strategies for this well needed
to minimize equivalent circulating density
(ECD) and surge pressures, which meant
that real-time measurements of hydrostatic
pressure and formation pressure would be
required for quick decision-making. De-pending
on formation characteristics and
pressures, drilling a slim hole in thin-mar-gin
sections of the well could be a contin-gency
option, if any other casing had to be
short-landed. However, an important well
objective was to reach the planned depth
without a slim hole. This objective could
be achieved only with contingency liners.
The most desirable solution was a liner
system, that could be run in tight tolerance,
provide required hang-off capacity, create
minimum surge, and provide clear indica-tions
of setting and disengaging the liner.
EXPANDABLE LINER HANGER
AND PACKER
Expandable liner hanger systems in the
7⅝-in. range have been deployed in deep-water
wells since the 1990s. The ELHP
system for the Saudi Aramco Red Sea well
was developed to extend ELHP capabili-ties
to handle hydraulics and large-sized
formation evaluation tools, as well as sub-sea
test strings for production test flow-rates.
Additionally, the thick-walled cas-ing,
inherent to sour service-rated tubulars
and high production pressures, above and
across reservoir sections, required a system
that would not be compromised and not
be burst- or collapse-limited within struc-tural
and geometric constraints.
The deepwater well was planned with
five strings of casing below the 18¾-in.
high-pressure housing, to which the 18⅝-
in. casing was attached. As is the practice
in casing design exercises, seismic-derived
PP and FG for shale and derived FG for
permeable intervals were used to identify
casing points.
To reach the proposed bottomhole
depth, the wellpath was expected to tra-verse
a normal PP-FG trend to the top of
salt (ToS), an unknown length of rubble
zone subtending a massive salt section,
regression of trend at base of salt (BoS),
and—at the time of well planning—three
divergent PP pathways that included
a total reversal to below hydrostatic
trend, if kerogens were present in the
deeper formations.
The marked inflection/regression in
the PP-FG suggested the need to use a
strong 14-in. casing with a 12.213-in. drift
to straddle the salt interval and the farthest
extent of the rubble zone. The geometric
constraint posed by this drift required an
uncompromising technical solution. Not
knowing what further challenges might ex-ist
below the PP-FG regression, the ELHP
offered the technical and deployment at-tributes
to exceed the required hang-off
capacity and isolation integrity desired.
The 11¾-in. ELHP system was planned
as a contingency string, primarily to ex-tend
isolation of the rubble zone below
the salt, should the 14-in. intermediate
casing be short-landed. For the unknown
length of the rubble zone, the planned
11¾-in. ELHP contingency string could
preserve the use of the preferred 9⅝-in.
high-collapse casing size across the up-per
reservoir section. The project team
believed that using the next casing size at
this depth—9⅝ in.—may have presented
through-borehole restrictions, should it
become necessary to call for the casing
point before reaching or traversing the res-ervoir
sections.
ELHP TECHNICAL DETAILS
The TORXS ELHP system comprises
two specific subsystems: the hanger packer
and the setting tool, also called the running
Fig. 1. Pre-drill PP-FG prediction and casing design.
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
Depth, fbsl
Pressure gradient data, pcf Casing design
Waterbottom
L.E.S.
Massive Mobile Salt
PPG FPG
OBG
Estimated RT-seabed-2,95 ft/
water depth-2,050 ft
Jet 36-in. conductor pipe
28-in. hole 24-in., 201#,
X-56, RL-4S casing
22-in. hole 18†-in.,
136#, L-80 casing
17-in. hole 14-in., 114#,
VM-95-SS casing
Planned contingency liner:
Drill 12-in. hole 14-in.,
UR hole 11¾-in., 65#, Q-125,
VAM FJL liner w/ELHP
±2,450 ft MD
±3,500 ft MD
±4,890 ft MD
±10,690 ft MD
±11,950 ft MD
26 in.
OIL COUNTRY TUBULAR GOODS

3. OIL COUNTRY TUBULAR GOODS
World Oil® / AUGUST 2014 47
tool. The hanger packer consists of metal
slips and a Baker Hughes ZX-style seal ele-ment.
The slips provide the hanging capac-ity,
while the ZX element seals the liner top.
The hanger packer incorporates a liner top
extension, with a polished bore receptacle
for stabbing seals of a tieback assembly and
also includes a special profile for transmit-ting
torque to the liner string through the
drill pipe and setting tool.
Unlike conventional liner systems, both
the hanger packer slips and ZX seal are set
by expansion forces generated by the set-ting
tool, which consists of an adjustable
swage with a hydraulic stroker, an anchor,
a flapper assembly, and a cement pack-off.
The running tool can be released before
cementing the liner, to eliminate the pos-sibility
of not being able to release from the
hanger after cementing, Fig. 2.
The ELHP running procedure in-volves
rotating and/or reciprocating the
system, while running in hole, if it is re-quired.
Once TD has been reached, a
ball is dropped and landed on a ball seat
within the setting tool. Pressure is applied
to the hydraulic stroker by dropping a ball
or closing the system, which causes the
adjustable swage to travel and expand the
hanger body. An overpull test will provide
a good indication that the hanger is set,
and the running tool is released. Pres-sure
is then increased to extrude the ball
through the ball seat within the setting
tool to reestablish circulation, release the
anchor, and reset the stroker. Cementing
operations can now be completed.
After the cementing, the flapper is
closed within the setting tool, just with
pipe movement, and pressure is again ap-plied
to the stroker. This second expansion
stroke is performed to further expand the
hanger body to set the ZX seal. Pressure is
then elevated to burst a rupture disc within
the flapper to reestablish circulation. The
packer seal should be tested at this point,
and the setting tool then retrieved.
Development of the 11¾-in. ELHP
necessitated full concept-to-prototype
engineering development and up-scaling
of several previous ELHP components
for deepwater application. An extensive
design qualification process during the
short concept-to-prototype cycle includ-ed
finite element analysis and modeling,
and exhaustive tests on components and
assemblies that made up the integral hang-er/
packer and tieback extension system
and the setting tool. Full function tests
also were performed for the entire hanger
packer setting sequence, followed by a
pressure test of the packer at full collapse
and burst pressures. The resulting system
combines wellbore isolation and deploy-ment
performance most suitable for pre-serving
through-bore casing size, without
compromising pipe strength, hanger ca-pacity,
or leak-path seal integrity.
The simplicity of the new ELHP
downhole components enhances reliabil-ity
by reducing susceptibility to additional
leak paths that are inherent with conven-tional
liner equipment. Because the run-ning
tool applies the setting force hydrauli-cally
and is load-neutral during run-in-hole
(RIH), the system can be set in highly de-viated
and horizontal wells, and subjected
to high circulation pressures, with no risk
of prematurely activating the setting mech-anism.
Additional advantages include less
limitation to the setting force applied to the
hanging slips, rapid confirmation that the
hanger is set and the liner is in place, and
greater wall cross-sectional contact, giving
the system the potential for higher pressure
and hanging capacity.
WELL CONSTRUCTION
The homogeneity of the salt section,
consistency, and low temperature (262°F
VSP temp.) created benign conditions
for drilling across the salt. Approximate-ly
5,800 ft of salt—mostly halite—was
drilled with a 17-in. hole. At 900 ft, from
the predicted BoS, a walkaway VSP survey
was carried out to provide a look-ahead for
formation and pressure transitions.
Rubble zones, rugose transition planes,
seams, welds, and protracted occurrences
of anhydrite/shale/sand sequences were
anticipated at BoS, as is expected in most
subsalt exploration wells. After analysis of
the VSP and quad-combo log data, a pre-cise
location for isolating the salt rubble
zone was identified.
A string of 14-in. casing was set at
10,689 ft, at a casing point below where a
second streak of anhydrites was confirmed.
With the salt behind casing, the next set
of challenges was to determine where the
PP transgression and regression inflex-ion
point occurred, make correct MW
adjustments, and refine predrill PP-FG
predictions. The drilling engineering and
exploration teams decided to use as many
formation-while-drilling measurements as
possible, to carefully navigate the PP ramp
and reversal, while managing drilling pa-rameters
and MW on the fly.
In preparation to ride the ramp, MW
was adjusted from 113 pounds per cubic
ft (pcf) to 118 pcf. As drilling progressed
from the bottom of the 14-in. casing, circu-lation
losses occurred, despite several ana-lytical
models indicating an 18-pcf window
between PP and FG. Lost circulation ma-terial
(LCM) was pumped and, with some
soak time, hole circulation was regained,
momentarily. Because only 200 ft of new
hole had been drilled below the 14-in. cas-ing
shoe, the option to run a liner to isolate
losses was not acceptable. Additionally, it
was important to know the vertical extent
of this loss zone.
The drilling BHA was modified, and
drilling continued with less-sensitive LWD
components, and a bit with bigger jets for
spotting LCM. Difficulty troubleshoot-ing
the losses was three-fold: 1) a lack of
returns to surface precluded physical de-scription
of the formation using cuttings;
Fig. 2. Close -up view of TORXS setting
tool (left) and setting tool schematic.

4. OIL COUNTRY TUBULAR GOODS
2) drilling ahead with losses prevented
placing LWD sensors to get petrophysi-cal
data; and 3) pressure-while-drilling
(PWD) data were erratic without a stable
annular fluid column.
Mud weight was reduced from 118 pcf
to 115 pcf, and then to 110 pcf, to enable
pumping at a higher flowrate. Dynamic
losses subsided at various modeled and
indicative fracture closure ECDs, and at
optimal flowrates. With a new equilibrium
established between drilling parameters
and formation mechanical and hydraulic
capacity, drilling progressed to section TD
and a total, drilled interval length of 1,345
ft. The hole was then underreamed from
12 in. to 14 in., to minimize surge effects
with ample annular clearance for the 11¾-
in. liner and to help increase trip speed. As
MW was adjusted to achieve the overbal-ance
to hold the gas back, the kick toler-ance
of the hole section diminished pre-cariously,
especially relative to the 18⅝-in.
casing shoe strength, Fig. 3.
Given the preceding well construction
progression, the decision to run the liner
was underscored by the desire to: 1) im-prove
the kick tolerance in the hole section;
2) isolate the lower-pressured shale forma-tion
just below the previous shoe; and 3)
increase mud weight to maintain well con-trol
in the progressively higher-pressured
zone at the bottom of the interval. As drill-ing
progressed beyond the depth of PP
regression, the well encountered a progres-sively
higher-pressured sandstone zone,
as indicated by increasing background gas
(average 10 to 70 units).
ELHP DEPLOYMENT
Job design and planning for the first
deployment of the evolutionary ELHP
technology required a meticulous assess-ment
of well status, load envelopes and
paths, operational hazards, and applica-tion
exigencies.
A Baker Hughes development engineer
inspected the ELHP in the shop, and noted
the larger cross-sectional area across one of
the setting tool assemblies, which neces-sitated
a cautionary run-in-hole note to be
added to the ELHP job program.
At the wellsite, after rigging up the top
drive head, the shoe track was run in hole
and the 11¾-in. joints were then run in at
a rate of 5 min. per joint. After the ELHP
assembly had been made up to the liner
string, a weight check was conducted, and
a pick-up of 320,000 lb and slack-off of
340,000 lb (including 240,000 lb for the
48 AUGUST 2014 / WorldOil.com
Fig. 3. Kick tolerance plot, showing diminishing tolerance margin
with increasing PP.
140
120
100
80
60
40
20
0
Kick tolerance calculation at 12,034 ft
PPest – 107 pcf; MW – 110 pcf; length of open hole – 1,345 ft
top drive) were recorded. The hanger/
packer assembly was visually inspected
for any damage, and was assessed to be in
excellent condition. The liner hanger as-sembly
was then lowered through the ro-tary,
and the drill pipe (DP) slips were set
on the lift nubbin. To prevent collapse or
damage, care was taken not to set slips on
the liner hanger/packer tieback extension.
As the liner assembly progressed
downhole, mud began flowing from the
drill pipe because of liner filling and the
reduced internal diameter of the DP, com-pared
to that of the liner. Trip speed was re-duced
from 5 to 25 min. per stand, to man-age
surge and piston effects of the 11¾-in.
liner in the 12.213-in. drift of the 14-in.
casing. With the liner string at the 14-in.
casing shoe, one liner volume of mud was
circulated at 400 gpm.
After a second weight check, 510,000 lb
of pick-up weight and 500,000 lb of slack-off
weight were recorded. It was decided
not to rotate the liner string, and tripping
proceeded into the
14-in. underreamed
open hole.
Three stands be-fore
reaching TD,
a 1¾-in. ball was
dropped and chased
with 2-bpm mud,
to help it reach the
float collar and con-vert
from autofill
to conventional. A
final weight check
recorded pick-up
of 530,000 lb and
slack-off of 520,000
lb. The space-out
of the liner string
was carried out with depths tide-corrected
to ensure location of the liner shoe at the
required depth of 11,950 ft. The packer ele-ment
was placed, as close as possible, in the
middle of a casing joint.
Pumps were activated to clear flow by-pass
areas and move fluid around the liner.
While circulating, returns were monitored
continuously to ensure that bridging in the
annulus would be detected promptly, should
it occur. Cementing lines were aligned and
flushed, while circulating to, further condi-tion
the hole and the mud. With circulation
completed, the 11¾-in. liner guide shoe
was placed at 11,950 ft, and the 2⅛-in. OD
hanger setting ball was released.
Approximately 34 min. after being
launched, a slight pressure indication on
surface confirmed that the setting ball had
landed on the ball seat. Pressure was gradu-ally
applied to 3,500 psi, then to 4,300 psi,
and finally to 4,750 psi. The running tool
was released automatically from the liner,
and the hanger was set.
After cementing, the stroker was low-ered
into reset position, and the anchor
was set. Pressure was brought up to 3,500
psi. Collet release was observed at 2,800
psi, and stroke action began downhole,
with pressure rising to 4,800 psi, to indi-cate
that the packer expansion process was
complete. Setting pressure was held at the
running tool for 30 sec, to allow the tool to
complete the second full stroke, Fig. 4.
PROJECT SUCCESS
Following a very short design and
development cycle, the 11¾-in. ELHP
was deployed flawlessly in its first field
application.
124 bbl
101 bbl
78 bbl
57 bbl
36 bbl
15 bbl
98
99 100 101 102
Pore pressure, pcf
Bbl
103 104 105 106 107
Fig. 4. TORXS expandable liner hanger
packer deployment process.

5. OIL COUNTRY TUBULAR GOODS
ACKNOWLEDGMENT
This article is adapted from SPE/IADC paper 166803, “World’s first
successful deployment of an advanced 11¾-in. expandable liner
hanger in a deepwater exploration well,” presented at the SPE-IADC
Middle East Drilling Technology Conference and Exhibition, Dubai,
UAE, Oct. 7-9, 2013.
REFERENCE
1. Al-Husseini, M.I. 2008, “Middle East geological timescale,”
GeoArabia, Journal of Middle East Petroleum Geosciences, 2008,
Vol. 13, No. 4, Gulf Petrolink, Bahrain.
YEMI ADEWUYA is the drilling
engineering supervisor at Saudi
Aramco with primary
responsibility for the Red Sea
Exploration Drilling Program.
Mr. Adewuya has 25 years of
industry experience spanning
well design and engineering, drilling and
evaluation systems application in extended
reach, and multilateral and deepwater wells. He
holds BS and MS degrees in mechanical
engineering from University of Ilorin and
Mississippi State University respectively, and an
MBA from Houston Baptist University.
SHRIKANT TIWARI is general
supervisor for drilling and
completion engineering in
Saudi Aramco. He has 27 years
of industry experience in field
and office positions for both
offshore and onshore
operations. Mr. Tiwari is leading exploratory
drilling projects for Saudi Aramco in Red Sea
and Arabian Gulf.
ABDULLAH ABDELWAHED is
an operations manager at Baker
Hughes. During his eight-year
career, Mr. Abdullah has
developed an expertise in
wellbore construction and
completions. He holds a BS
degree in mechanical engineering.
MAURILIO SOLONO is the
systems integration manager
for completion and production
systems at Baker Hughes. Mr.
Soloni has extensive experience
working with intelligent well
systems, liner drilling, sand
control, openhole wellbore isolation and
expandable liners. He has worked in several
countries globally over his 22-year career in the
industry. He holds a BS degree in mechanical
engineering and an MBA from TEC Monterey-
ESPE.
Article copyright © 2014 by Gulf Publishing Company. All rights reserved. Printed in U.S.A.
50 AUGUST 2014 / WorldOil.com
Not to be distributed in electronic or printed form, or posted on a website, without express written permission of copyright holder.