1.
Abstract
Introduction: As wells with existing gas lift (GL) installations mature and reservoir pressures decline conventional
GL systems often become less efficient. The lack of reservoir pressure makes it difficult to maintain a fluid level at
a depth that allows the existing GL system to be effective. The cost of a work over remediation program to
redesign and rerun the existing GL system can at times be considered uneconomical.
Application: This innovative “Capillary Conveyed” through tubing system can be applied to most wellbores
regardless of tubing size or depth.
Results, Observations, and Conclusions: The first “Capillary Conveyed GL extension system installation was
carried out for a major operator offshore Vietnam in January 2012. The existing GL system was no longer effective.
The well was unable to flow and was shut in. After the installation the well took several days to unload and stabilize
but then flowed continuously for 60 days at rates that exceeded the operator’s expectations. After the initial 60
days production the well started to fluctuate and has since been put on a cyclical production regime. Cumulative
production from the well from the date of the GL Extension System installation until May 2012 was 43,000 bbls oil.
Project payout was estimated to be 4 days.
Significance of Subject Matter: Wells that were once considered uneconomic due to cost, technical challenges
and/or accessibility may now be re-evaluated as candidates for this new technology. This innovative through tubing
solution has the potential to reinstate flow to wells where the existing GL system is no longer effective. Furthermore
the system can be adapted to allow a new through tubing GL system to be introduced into a well that was
completed without a gas lifting system.
Technical Contributions: Advanced solutions utilizing “Capillary Technologies” provide cost effective production
enhancement and improved reserves recovery while maintaining a relatively small foot print. This paper will review
a case history where this “Capillary Conveyed” through tubing solution was successfully installed and reinstated
flow in a well that was suffering from an inefficient GL system.
Field Overview: Block 46/02 (Graphic 1) is located 205km offshore south of Ca Mau, the southernmost land fall of
mainland Vietnam, and just north of the joint development area PM-3 CAA. The producing Kekwa oil and gas field
in PM-3 CAA is located 15km to the southeast of Song Doc Area (SDA).
Block 46/02 was established on 12
th
December 2002. The Truong Son Joint Operating Company (TSJOC) was
established to explore for and produce oil and gas from the Block on behalf of the founding partners: PetroVietnam
Exploration and Production Company (40%), Petronas Carigali Overseas Sdn. Bdh (30%), and Talisman (Vietnam
46/02) Ltd. (30%).
IPTC Paper Number: 16192
Extending Gas Lift Systems Deeper into the Wellbore Using Capillary Through
Tubing Services
Brad Pate - Baker Hughes Thailand, Rick Stanley - Baker Hughes Singapore, Nguyen Chinh Nghi -
TRUONGSON JOC Vietnam
Copyright 2013, International Petroleum Technology Conference
This paper was prepared for presentation at the International Petroleum Technology Conference held in Beijing, China, 26–28 March 2013.
This paper was selected for presentation by an IPTC Programme 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 International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily
reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society
Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology
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acknowledgment of where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax +1-972-952-9435

2.
2 IPTC Number 16192
Graphic 1 – Block 46/02 is located 205km offshore south of Ca Mau, the southernmost land fall of mainland
Vietnam, and just north of the joint development area PM-3 CAA.
The Block-46/02 Song Doc field (Graphic 2) was developed using a simple fixed wellhead platform (SDA), with 16
producing strings in single and dual completion wells, with a spread moored Floating Production Storage and
Offloading vessel (FPSO). The FPSO facility was designed to separate well fluids, provide for gas lift to the wells,
treat produced water and store and export oil. Under the leasing agreement, the FPSO owner supplies systems
designed to be as simple as possible to reduce complexity, maintenance requirement and manpower and ensure
minimum downtime.
Graphic 2 – Song Doc field detail

3.
IPTC Number 16192 3
Well Completion Philosophy: Production and Nodal Analysis studies concluded that optimum tubing size based
on known fluid properties and pressures of the SDA field is 3-1/2” tubing for all the wells. This was also consistent
with current production data from analogous reservoirs in nearby Malaysian waters.
There are some options for well completion which have application at Song Doc development wells:
 Dual completion
 Single completion
 Monobore completion
Dual and Single completion types are commonly used in adjacent Malaysian fields with some success while the
monobore concept has also been applied successfully for both oil or gas wells in the Gulf of Thailand.
The specific well NH-1P, planned to access one sand reservoir, both single and monobore completion techniques
were considered. The single, packer type completion is more generally applied to high PI, single sand reservoirs
where larger diameter guns are required in order to optimize productivity whereas in general, the monobore type of
completion is best suited to smaller reservoirs where completion of the smaller zones can often be uneconomic in
a single completion type.
In reviewing the various options, it was considered that while the Song Doc development did not fit clearly into one
category or another the studies suggested that where two or more reservoirs are targeted, the monobore concept
should be applied where only single reservoirs are targeted and so monobore completion was selected for NH-1P
but with one gaslift mandrel in the tubing.
Well History: NH-1P (Figure 1) is a monobore Oil Producer and started production from November 2010. In its
production history the well has been intervened several times to restore production due to sand bridge formed in
the wellbore. Besides the sand production and sand bridge issue, there was only one gaslift mandrel installed high
above the packer. It was predicted that when reservoir pressure depleted with time there would be a point that fluid
level would fall below the gaslift mandrel depth and hence an insert string for gaslift deepening is required for the
well to continue to produce. Various insert string options were considered:
 Convention 2” 13Cr coiled tubing string with gaslift mandrel installed on coiled tubing and thru-tubing
straddle packers
 Capillary string / Macaroni / dip tube by using coiled tubing from 5/8” to 1” to deepen the gaslift injection
point to top of reservoir with hardware proposals from various providers
In August 2011 the NH-1P production ceased. Findings from slickline pressure survey investigation after that
revealed that there was no sand fill-up in the wellbore and fluid level in the well was below the gaslift mandrel in the
well.
All the insert string options above were reviewed again. Lead time of hardware and equipment weight are the main
decision criteria. The Extending Gas Lift Systems using Capillary thru-tubing service was chosen because
hardware could be delivered in December 2011 and the operation could take place immediately even in December
during rough sea season because equipment weight is light enough to be lifted safely to wellhead platform during
rough sea season.

4.
4 IPTC Number 16192
Figure 1 – Wellbore Schematic – Pre Capillary Work
NH - 1P
m MDDF TVD
3 250 250 SCSSV-TRSV
FLOW COUPLING
19 500 496 X NIPPLE
55 1207 961 SPM
(Orifice 3/16")
FLOW COUPLING
55 1468 1144 SSD ASSEMBLY
FLOW COUPLING
55 1484 1150 XN NIPPLE (2.75" BORE)
57 1500 1160 LINER HANGER
57 1650 1240 7" CASING SHOE
3301
3361
3-1/2" TUBING LANDING COLLAR
3-1/2" TUBING SHOE
DEPTH COMPLETION STRING
3-1/2", 9.2PPF, 13Cr L-80 KS Bear
EQUIPMENT
2.900
2.813
2.813
MAX OD
IN
MIN ID
IN
2.900
2.900
2.992
3.920
5.030
3.920
3.960
3.960
4.540
5.230
COMPLETION SCHEMATIC
MONO-BORE OIL PRODUCER
2.690
Dev
Deg
FLOW COUPLING
2.900 3.920
2.813
2.900 3.920
I-50: 3192-3209 m MDDF (17 m)

5.
IPTC Number 16192 5
Post Installation Production Performance: The well was unable to flow and was shut-in before the Capillary
String installation. After the installation completed in mid Jan 2012 (Figure 2) the well took several days to unload
and stabilize but then flowed continuously for 60 days at rates that exceeded the operator’s expectations. After the
initial 60 days production the well started to fluctuate and has since been put on a cyclical production regime.
Cumulative production from the well from the date of the GL Extension System installation until May 2012 was
43,000 bbls oil. Current NH-1P completion diagram as below with 0.75” capillary string installed.
Figure 2 – Post Capillary Wellbore Schematic with Gaslift Extension Installed
COMPLETION REPORT
FIELD : SONG DOC SIZE WEIGHT GRADE DEPTH (M) COMPLETION TYPE :
WELL : NH-1PST1 7 47 L-80 1650.000 Dual Oil/gas Producer
DATE : 20 Mar 2012 - - - 0 COMPLETION FLUID :
TSJOC REPS : JOHN TAGGART TUBING L/S 3 1/2" 9.2 13CR 1499.011 10.2 ppg NACL
IAN
HALLIBURTON REPS : FRANCIS TANG SALES ORDER NO : 6361200
TRAN CAO DUNG
Max deviation: 57.99 deg @ 1383.65m MDDF WilSuperior PICK UP WT: 95 LBS SLACKOFF WT: 88 LBS BLOCK WT: 66K LBS C/LINE PROTECTORS: 21
DEPTH (M) ID OD NO. DEPTH (M) DEV (
O
) ID OD
1 1 SINGLE TUBING HANGER 28 0
FLOW COUPLING 244 5 2.880 3.898
2A STORM CHOCK 2A 2 2 TR-SCSSV 245 5 2.813 5.030
(installed in Apr 2011) FLOW COUPLING 246 5 2.880 3.898
3 3 X-NIPPLE 2.813" BORE 495 16 2.813 3.898
4A INNER STRING 4A 4 4 SIDE POCKET MANDREL 1207 56 2.992 5.360
(ORIFICE VALVE)
FLOW COUPLING 1467 57 2.880 3.898
5 5 "XD" SLIDING SIDE DOOR 1467 57 2.813 4.550
FLOW COUPLING 1469 57 2.880 3.898
6 6 XN-NIPPLE 2.75" BORE 1483 57 2.690 3.898
8 WEATHERFORD POLISHED 1496.550 5.290 5.760 8 7 7 WEATHERFORD NO-GO RING 1496 57 5.050 5.800
BORE RECEPTICLE WEATHERFORD SEALS 1498 57 4.320 5.250
WEATHERFORD MULESHOE 1499 57 4.320 5.250
EOT 1499 57
Landing Collar 3302 57 2.930 3.830
Float Collar 3312 57 2.950 3.900
Float Shoe 3360 57 5.700 6.380
JFE Bear
LONG STRING
DESCRIPTION THREAD
CASING VAM TOP
LINER -

6.
6 IPTC Number 16192
Project Objective: Install a through tubing system that will allow for the diversion of the gas lift injection gas from
the bottom most gas lift valve in the completion to a pre-determined depth below the packer.
Engineering Design: The subject well for the first installation of this new and innovative system was highly
deviated with a 57.60 degree section starting at 1006m and extending until TD at 3366m where the deviation built
up to 62.84 degrees (Figure 3). To assure project success extensive engineering and program design was
completed. Tubing force analysis (TFA) (Figure 4) was carried out to assure that well bore access was achievable.
This analysis also supported the final specifications for the tubulars that would be left downhole on a semi-
permanent basis in a high CO2 environment of more than 35%. A 2205 Super Duplex Alloy material with a 110ksi
tensile rating was selected for the tubing. The high tensile rating would allow for the tubing to be pushed to target
depth with the coiled tubing injector head without the risk of buckling. In addition, further simulations were carried
out to define the optimum gas lift injection rate and confirm that friction losses in the 0.75in OD extension would not
compromise lift efficiency.
System Design: The unique design of the system allows it to be a considered as a production enhancement
solution applicable to any wellbore where gas can be injected down the annulus and diverted into the production
tubing. Typical annulus to production tubing communication devices are, sliding side doors, side pocket mandrels
or could simply be perforated tubing. The main component of the system which is the injection sub (Figure 5) was
designed and engineered to have the largest possible flow area while maintaining sufficient integrity to securely
attach the 0.75in OD extension and maintain the critical flow area for the injection gas. HNBR elastomers were
selected for all components due to the high CO2 concentrations. All system components were manufactured from
13Cr material. The connection of the extension to the injection mandrel was pull tested to 7000lbs (Figure 6) as
part of the manufacturing QA/QC process.
Deployment Equipment: A Micro-Coil/Capillary Unit was chosen for the deployment and program execution
based on its diverse range of tubing size deployment capabilities and its small light weight foot print (Figure 7).
The unit was air freighted to Vietnam from the United Kingdom to meet the operator’s short time frame and window
of opportunity.
Well Preparation: Prior to mobilization of the Micro-Coil/Capillary Unit conventional slickline methods were used to
drift the tubing, locate and confirm the depth of the targeted gas lift side pocket mandrel, clean the tubing in the
area where the elastomers will seal against the tubing wall and set the lower tubing stop.
Installation Sequence: The system is made of four major components (Figure 8). From the lower most to the
upper most these components are:
 The lower tubing stop
 The lower pack off assembly with the injection sub and the extension tube attached
 The upper pack off assembly
 The upper tubing stop
It should be noted that the depth correlation for the lower tubing stop is critical as it defines the depth of all other
components that will be installed above it. The system components are deployed using conventional wire line and
coil tubing technologies and methods. Six basic steps are required to install the system. They are listed below:
1. Run and set the lower tubing stop with slickline
2. Run the predetermined extension with the “Micro-Coil/Capillary” injector head
3. Run and set the upper packoff assembly with the extension connected to it on top of the bottom tubing
stop with the “Micro-Coil/Capillary” injector head
4. Run slickline to jar down and energize the lower packoff element
5. Run the upper packoff assembly and sting into the polished bore of the lower packoff and jar down with
slickline to energize the packoff element
6. Run and set the upper tubing stop with slickline
The completed system installation is demonstrated in Figure 9.

7.
IPTC Number 16192 7
Conclusion: This innovative through tubing system can be safely and effectively installed using Capillary
Techniques and deployment equipment. Existing inefficient gas lift systems and/or well bores without gas lift
systems can now be considered candidates for this cost effective solution as opposed to a costly work over
program.
References:
1. Baker Hughes Case History: Capillary ExtendLift ™System Restores Lost Production January 2012.
2. Baker Hughes post job report January 2012
3. Baker Hughes Circa Simulation Software
4. WAPRE International drawings and photographs
Acknowledgements: The authors would like to give special thanks to TRUONGSON JOC Vietnam and Baker
Hughes Thailand for allowing this paper to be published. Special recognition should go to Ashley Wyper and the
Baker Hughes team in Vietnam that supported the successful installation of the system.

8.
8 IPTC Number 16192
Figure 3: Well Bore Profile
Figure 4: Tubing Force Analysis
- 600
- 300
0
300
600
9 0 0
1 2 0 0
1 5 0 0
1 8 0 0
Easting(m)
- 2100
- 1800
- 1500
- 1200
- 900
- 600
- 300
0
300
TVD(m)
- 2 1 0 0
- 1 8 0 0
-1500
-1200
-900
-600
-300
0
300
N o r t h i n g (m )
W e ll N H -1 P ST 1
-2 0 0 0
-1 5 0 0
-1 0 0 0
-5 0 0
0
5 0 0
1 0 0 0
0 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0
E x p e c te d W e ig h t G a u g e a n d O p e r a tin g L im its D u r in g R I H
WeightGaugeReading[lbf]
B H A D e p th [m ]
W e ig h t G a u g e F ric tio n L o c k L im it
A c tu a l W e ig h t G a u g e O p e ra tin g L im it
Project Title: Packoff ExtendLift
Field-Well: SONG DOC -- NH-1P ST1
Company-Client: Truong Son JOC
File: C:Documents and SettingsbradpateDesktopVietnamTrung SonTruong Son JOC Packoff ExtendLift.c32
Analysis: Wednesday, March 02, 2011 3:07:59 PM
Scenario: ExtendLift .075" x .089"
-0
2 5 0 0
5 0 0 0
7 5 0 0
1 0 0 0 0
0 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0
E x p e c te d W e ig h t G a u g e a n d O p e ra tin g L im its D u r in g P O O H
WeightGaugeReading[lbf]
B H A D e p th [m ]
W e ig h t G a u g e F ric tio n L o c k L im it
A c tu a l W e ig h t G a u g e O p e ra tin g L im it
Project Title: Packoff ExtendLift
Field-Well: SONG DOC -- NH-1P ST1
Company-Client: Truong Son JOC
File: C:Documents and SettingsbradpateDesktopVietnamTrung SonTruong Son JOC Packoff ExtendLift.c32
Analysis: Wednesday, March 02, 2011 3:10:24 PM
Scenario: ExtendLift .075" x .089"

9.
IPTC Number 16192 9
Figure 5: Injection Sub Figure 6: Injection Sub Pull Test Chart
Figure 7: The Micro Coil/Capillary Deployment Unit

10.
10 IPTC Number 16192
Figure 8: System Components

11.
IPTC Number 16192 11
Figure 9: Completed Installation