Expandable Liner Hanger: A Reliable Liner Top Isolation System

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Copyright 2002, Offshore Technology Conference 
 
This paper was prepared for presentation at the 2002 Offshore Technology Conference held in 
Houston, Texas U.S.A., 6–9 May 2002. 
 
This paper was selected for presentation by the OTC Program Committee following review of 
information contained in an abstract submitted by the author(s). Contents of the paper, as 
presented, have not been reviewed by the Offshore Technology Conference and are subject to 
correction by the author(s). The material, as presented, does not necessarily reflect any 
position of the Offshore Technology Conference or its officers. Electronic reproduction, 
distribution, or storage of any part of this paper for commercial purposes without the written 
consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print 
is restricted to an abstract of not more than 300 words; illustrations may not be copied. The 
abstract must contain conspicuous acknowledgment of where and by whom the paper was 
presented. 
 
Abstract 
Initial liner top integrity is a primary concern for most 
operators. If the liner top fails routine or regulatory integrity 
tests, expensive and time-consuming remedial operations 
increase direct costs for equipment and services. This 
remediation delays well completion, which ultimately delays 
revenue generation. These expenses often exceed the initial 
cost of the liner equipment. Liner top failure continues to 
challenge the industry despite improvements in integrally run 
liner top packers, special cements, and cementing pratices. 
Even newer generation liner top packers, run either integrally 
with the liner hanger or as a second trip packer, have multiple 
sealing surfaces that must function under rigorous conditions 
to achieve liner top isolation. 
 
The expandable liner hanger has been developed and 
successfully field-tested as an alternative to conventional 
“cone and slip” liner hangers and liner top isolation packer 
systems. The expandable liner hanger combines the functions 
of the liner hanger and the isolation packer into a single 
component. The expandable liner hanger uses elastomeric 
“bands” to provide the axial load capacity of a conventional 
liner hanger and the annular sealing capability of the liner top 
isolation packer. The expandable liner hanger is expanded 
hydraulically with the liner running/setting tool assembly. 
During expansion, the elastomeric bands are compressed into 
contact with the ID of the supporting/intermediate casing, 
virtually eliminating the annular space between the liner 
hanger and the casing. 
 
This paper discusses expandable liner hanger design 
criteria and testing undertaken to qualify the expandable liner 
hanger as a reliable liner top isolation system. Initial field 
installations and the lessons learned are also discussed. 
Introduction 
The importance of the liner-casing overlap is illustrated by the 
efforts and expense taken by operators to ensure hydraulic 
integrity of the overlap. Typical methods of achieving pressure 
integrity include the following: 
• Cement “squeezes,” including a liner top packer as a 
component of the initial liner hanger setting 
• One or more “second-trip” liner top isolation packers 
installed to control gas migration at the liner top 
The typical liner top is complex in its design (Fig. 1) and can 
develop leaks due to a myriad of causes1. 
 
A recent informal survey of several GOM operators 
revealed that 30 to 50% of pressure seals in overlaps fail. One 
operator made a concerted effort to improve liner running and 
cementing procedures. Data gathered over an 18-month period 
was used to shed light on possible causes of overlap failure by 
gathering information on liner/casing sizes, types of 
equipment, overlap length, mud data, annular cross section, 
equipment, and service suppliers. The study concluded the 
chances of having a liner overlap seal failure did not depend 
on any single factor and the chances for an incident were 
nearly the same regardless of the factors associated with any 
given well2. 
 
The development and successful deployment of solid 
expandable tubulars improved the probability of eliminating 
liner top leaks and reducing the associated remediation costs. 
The expandable liner hanger is a byproduct of developing 
expandable openhole and expandable cased-hole liners3. The 
design features of the anchor joint – elastomeric seals used to 
seal and anchor the expanded liner to the casing ID – were 
adapted to run and hang conventional, non-expanded liners 
(Fig. 2). 
 
Expandable Liner Hanger Design 
Initial design criteria for the expandable liner hanger include 
the following: 
• Incorporate solid expandable tubular features into 
expandable anchor joints to provide maximum axial load 
capacity and pressure integrity at the liner/casing annulus 
 
OTC 14313 
Expandable Liner Hangers: Case Histories 
Melvin J. Moore, BP America Inc.; Donald B. Campo, Shell International Exploration & Production; Joel Hockaday, 
Enventure Global Technology; Lev Ring, Enventure Global Technology 
2 M. MOORE, D. CAMPO, J. HOCKADAY, AND L. RING OTC 14313 
• Minimize expandable liner hanger OD for maximum 
running clearance while maintaining axial load and 
pressure performance 
• Provide rotational and reciprocation capability in the liner 
running/setting tool assembly 
• Maximize running/setting tool reliability as well as total 
system reliability 
• Simplify the running/setting tool cementing 
pack-off system 
• Incorporate conventional cementing wiper plug systems 
and standard float equipment into the expandable liner 
hanger system 
 
System Specifications 
Initial expandable liner hanger specifications included 
the following: 
• Capable of “setting” in 9-5/8 in., 47 to 53.5 lb/ft casing and 
suspending 7-5/8 in. or smaller liners. 
• Capable of suspending a minimum of 250,000 lb of liner 
weight at 250ºF with standard oilfield nitrile elastomer 
compounds (other compounds are available to increase the 
temperature range to 400ºF). 
• Provide a working pressure of 8,000 psi in burst and 4,000 
psi in collapse. 
• Qualify system to ISO/DIS 14310 guidelines for 
packer systems. 
 
System Qualification 
Initial qualification tests included the following: 
• Testing potential expandable liner hanger body materials to 
determine expansion parameters and suitability. This 
evaluation also included FEA analysis techniques (Fig. 3). 
• Establishing potential elastomer characteristics when 
exposed to temperature and common oilfield fluids. 
• Testing the bond quality of various elastomers when 
applied to the liner hanger body. 
• Determining the expansion characteristics of the liner 
hanger body with elastomeric bands in place. 
• Qualifying lab-expanded expandable liner hanger sections 
in fluid and gas environments. 
• Qualifying mechanical load capacity and pressure integrity 
when expanded into supporting casing. 
• Function testing of the liner running/setting tool assembly. 
• Full-scale testing of the expandable liner hanger system in 
a deep well simulator. 
• Field testing the expandable liner hanger system. 
 
The qualification test for the expanded liner hanger system 
entailed expanding a 1-foot section of the expandable liner 
hanger/liner hanger packer. The 7-5/8 in. base section was 
expanded into a section of 9-5/8 in. casing that was cemented 
into a section of 13-3/8 in. casing to simulate actual equipment 
usage (Fig. 4). This test established an axial load capacity of 
over 580,000 lb for the single element section and pressure 
integrity of 11,400 psi was achieved (Fig. 5). 
Deep well simulator testing was conducted on a full-scale 
system. The 7-5/8 x 9-5/8 in. expandable liner hanger/liner 
hanger packer, using five elastomeric bands, was set using the 
running/setting tool assembly. The 9-5/8 in., 53.5 lb/ft casing 
was set in the simulator and the expandable liner hanger 
assembly was placed in position (Fig.6a). The casing and the 
expandable liner hanger assembly were heated to 300ºF. After 
temperature stabilized, the expandable liner hanger was “set” 
(Fig. 6b) and the running/setting tool assembly was retrieved. 
Testing confirmed the expandable liner hanger assembly met 
or exceeded the initial design parameters. Subsequent testing 
established a total “hanging” capacity in excess of 750,000 lb 
at temperature. After further testing, the expandable liner 
hanger body was sectioned for evaluation (Fig. 7 and Fig. 8). 
 
Case Histories 
Field Testing Criteria. Following the successful deep well 
simulator test, the first field test was conducted on a non-
producing well in South Texas destined for plugging and 
abandonment that belonged to Shell Exploration and 
Production Company (SEPCO). The second field test, also in 
South Texas, was for a drilling liner for a commercial 
application on a BP well. The field test sequence was selected 
for proof of concept: 
• Run and set the liner under actual conditions 
• Prove the system’s ability to provide pressure integrity at 
the liner/casing overlap 
 
The operational issues involved were discussed at length 
and detailed procedures were developed to ensure safety while 
achieving the goals of successful equipment deployment. 
Detailed planning consisted of the following: 
• Outline of the operational overview of running the 
expandable liner hanger system 
• Planned sequences 
• Checkpoints 
• Contingencies 
• Results of running the expandable liner hanger system 
 
First Field Test. The first field test was conducted at Shell’s 
Hinojosa No. 8 well, in Fandango Field in Jim Hogg County, 
Texas. Since there was no risk of lost production and to 
maximize the value of the test, SEPCO opted to test both the 
expandable liner hanger system and the expandable sand 
screen system. As a result of the sand screen testing, liner 
cementing operations were eliminated. The Hinojosa well was 
cased with 9-5/8 in., 53.5 lb/ft casing to plug back depth. The 
bottomhole temperature was approximately 140ºF. 
 
To ensure appropriate evaluation of the system functions 
and procedures, a casing inspection log and a casing scraper 
run were made before running the expandable liner hanger and 
expandable sand screen assembly. The casing was filled with 
9.5 lb/gal water based mud and tested to 4,000 psi to ensure 
casing integrity. 
 
OTC 14313 EXPANDABLE LINER HANGERS: CASE HISTORIES 3 
After initial preparations, the 285-foot expandable sand 
screen assembly was picked up and run into the hole. The 
expandable liner hanger assembly, including the liner 
running/setting tool, was picked up and made up to the spacer 
joint at the top of the expandable sand screen assembly. The 
running/setting tool assembly was made up to 4-1/2 in. tubing 
and run to the setting depth, with the top of the liner at 
approximately 3,200 ft (Fig. 9). 
A choke manifold system was incorporated into the 
pumping system to permit the controlled flow rate 
(approximately 5 to 8 gal/min) at anticipated expansion 
pressures of 4,000 psi. Pressure and flow rates were captured 
during the expansion process. Prior to hanger expansion, 
appropriate lines were tested to 7,000 psi and an automatic 
kick-out on the pump truck was set at 6,500 psi 
and function-tested. 
After all systems were checked and the appropriate safety 
meetings were held, the system was slowly brought up to 
pressure and the expandable liner hanger system was 
successfully expanded. Expansion pressures were in line with 
normal parameters. The running/setting tool bypass ports, 
indicating completion of the expansion process, functioned 
properly. The running/setting tool was released by slacking off 
weight to release the collet locking system, and the running 
tool was released and pulled out of the hole. 
The expandable sand screen system was expanded using a 
separate expansion assembly. Following the sand screen 
expansion, a caliper log was run on a wireline to ascertain the 
ID of the expanded liner hanger. The expanded ID was 
approximately 7.58 in., as expected. A test packer was run and 
set above the liner top to verify pressure integrity. Test 
pressure at 3,800 psi held for approximately 45 minutes. 
When all testing was complete, the well was prepared for 
abandonment per Texas Railroad Commission requirements. 
 
Second Field Test. The second field test was actually the first 
application of the expandable liner hanger technology in a 
commercial well. This test was conducted on BP’s McLean 
Heirs No. 7 well in the Northeast Thompsonville Field of Jim 
Hogg County, Texas. Since this application was a drilling 
liner, the liner was to be cemented to provide a full-scale 
operational test of the expandable liner hanger system. 
 
The McLean Heirs well was cased with 9-5/8 in., 43.5 lb/ft 
casing, except the bottom five joints, which were 9-5/8 in., 
53.5 lb/ft casing. This configuration permitted using the 
original size expandable liner hanger equipment without 
having to run qualification tests for a different weight range 
system. The 7-5/8 in., 29.7 lb/ft L-80 STL liner was run to a 
depth of 11,797 ft. The top of the liner was 8,211 ft., for a total 
of 3,586 ft and a buoyed weight of approximately 80,000 lb 
(Fig. 10). The bottomhole static temperature (BHST) was 
250ºF and the oil-base mud weight was 
approximately 16 lb/gal. 
In this case, the expandable liner hanger was run with 
auto-fill float equipment and a J-type circulating sub above the 
liner running/setting tool assembly. The liner was run on 5 in. 
19.5 lb/ft drill pipe to the setting depth. A choke manifold, as 
previously run, was planned and used to ensure controlled 
flow and pressure rates for expanding the liner hanger. 
 
The 7-5/8 in., 29.7 lb/ft liner was run according to plan and 
the expandable liner hanger assembly, including the 
running/setting tool assembly, was made up to the top joint of 
casing. The running tool was made up to the first joint of drill 
pipe, the circulating sub was installed, and the liner was run 
into the hole following normal liner running procedures. 
 
When setting depth was reached, a pump-in sub was made 
up to the work string, the circulating sub was closed, and the 
liner was cemented conventionally. After cementing was 
complete and the liner wiper plug bumped, the circulating sub 
was opened and the hole was reverse-circulated above the 
liner top to remove any excess cement. The expansion setting 
ball was dropped and pumped to the setting tool. High-
pressure lines were rigged up to the choke manifold. Data 
acquisition equipment was rigged up to record expansion 
pressures and flow rates and lines were tested. 
 
After the setting ball reached the ball seat in the setting 
tool, the system was pressurized to 4,000 psi to initiate 
expandable liner hanger expansion. Expansion was achieved 
at the planned pressures and rates. When expansion was 
complete, the bypass ports in the running/setting tool assembly 
functioned as designed and the pressure dropped, indicating 
completion. Weight was slacked off on the setting tool, 
allowing approximately six inches of travel to release the 
collet lock system. 
 
The running/setting tool was picked up above the liner top, 
the rams were closed, and the liner top tested to 2,000 psi with 
16 lb/gal fluid in the hole. After liner top testing was 
complete, the running tool assembly was retrieved. Drilling 
operations resumed. The well was drilled to total depth (TD) 
and completed. 
 
The first application of the expandable liner hanger in a 
commercial well environment was successful and established 
that cementing operations could be conducted normally with 
this new technology (Fig. 11). 
 
Lesson learned: 
Extra choke manifold and flowmeters are not necessary for 
successfully operating the expandable liner hanger system. 
Suitable flow rates and control can be provided by pumping 
systems normally used when cementing liners.The expandable liner hanger running/setting tool assembly 
did not have a drill pipe pup joint made up onto the top of the 
tool when picked up. This omission caused some delay, but 
4 M. MOORE, D. CAMPO, J. HOCKADAY, AND L. RING OTC 14313 
has been corrected by making up the proper pup joint prior to 
shipping the equipment to location. 
 
The spacer tube to connect the liner wiper plug assembly 
to the expandable liner hanger running/setting tool was too 
short and required additional time and effort to connect the 
plug assembly on location. This situation has been rectified. 
 
Time spent in planning a liner installation identifies the 
risks, defines the contingencies, and permits proper 
operational actions when the equipment is actually run. All 
parties are aware of potential problems and the actions 
required for successfully installing the equipment safely 
and efficiently. 
 
Conclusions 
The expandable liner hanger system provides a viable, 
technologically advanced method of running and cementing 
liners. Operational efforts are only moderately different from 
those used for conventional liner systems. Expansion of the 
expandable liner hanger/liner hanger packer after cement 
placement adds minimal risk with proper tools, techniques, 
and planning prior to running the liner. The expandable liner 
hanger system improves liner top integrity, significantly 
reduces the annular area between the liner hanger packer after 
expansion, and virtually eliminates any gas migration paths. 
 
References 
1. J. Agnew and R. Kline, “The Leaking Liner Top”, SPE paper 
12614, 1984 SPE Deep Drilling and Production Symposium, 
Amarillo, Texas, April 1-3, 1984. 
2. C. Lee Lohoefer and Ben Mathis, Unocal; David Brisco, 
Halliburton Energy Services; Kevin Waddell, Lev Ring, and 
Patrick York, Enventure Global Technology; “Expandable 
Liner Hanger Provides Cost-Effective Alternative Solution”, 
IADC/SPE paper 59151, 2000 IADC Drilling Conference, New 
Orleans, Louisiana, February 2000. 
3. Filippov, A., et al.: “Expandable Tubular Solutions”, SPE paper 
56500 presented at the 1999 SPE Annual Technical Conference 
and Exhibition, Houston, Texas, October 3-6, 1999. 
 
OTC 14313 EXPANDABLE LINER HANGERS: CASE HISTORIES 5 
Fig. 1 – Conventional Liner-Top Packers 
 
 
Fig. 2 – Expandable Liner Hanger/Liner Hanger Packer “As Set” 
 
 
 
Potential Leak Paths 
6 M. MOORE, D. CAMPO, J. HOCKADAY, AND L. RING OTC 14313 
Fig. 3 – Finite-element analysis used to study stresses during the design of the expandable liner hanger system. 
 
 
 
 
 
Fig. 4 – Test Fixture to Determine Hanging Weight and Seal Effectiveness 
 
 
OTC 14313 EXPANDABLE LINER HANGERS: CASE HISTORIES 7 
Fig. 5 – Liner Hanger Tests 
 
 
 
 
Fig. 6 – Expandable Liner Hanger Before and After Expansion 
 
 
 
Figure 6a - Before Expansion Figure 6b - After Expansion 
 
8 M. MOORE, D. CAMPO, J. HOCKADAY, AND L. RING OTC 14313 
Fig. 7 – Expandable Liner Hanger Body Sectioned for Evaluation. 
 
 
 
 
Fig. 8 – Expandable Liner Hanger Body Sectioned for Evaluation. 
 
 
 
OTC 14313 EXPANDABLE LINER HANGERS: CASE HISTORIES 9 
Fig. 9 – First Installation of an Expandable Liner Hanger System 
 
 
 
10 M. MOORE, D. CAMPO, J. HOCKADAY, AND L. RING OTC 14313 
Fig. 10 – First Application of Expandable Liner Hanger Technology in a Commercial Well 
 
McLean Heirs Jim Hogg #7 Well
17-1/2 in. hole
13-3/8 in. at 2,011 ft
12-1/4 in. hole
Top of liner
at 8,211 ft
9-5/8 in. at 8,737 ft
8-1/2 in. hole
7-5/8 in., 29.7 lb/ft, P-110, STL Liner
for 8,211 - 11,797 ft
6-3/4 in. hole
 5th Hinnant Perfs
3-1/2 in. at 13,800 ft
13,800 ft TD
OTC 14313 EXPANDABLE LINER HANGERS: CASE HISTORIES 11 
Fig. 11 – Expandable Liner Hanger Running Sequence 
 
 
 
 
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