SPE 126108

HP/HT Well Intervention by Coil Tubing—East Coast Case Histories

Haidher Syed Gaus Mohammad, SPE, BJ Services Company

Copyright 2010, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Oil and Gas India Conference and Exhibition held in Mumbai, India, 20–22 January 2010.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers 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 SPE copyright.

Abstract
Coil tubing is a single string of pipe, which can intervene into wells and perform specific jobs without mobilizing a rig.
The basic applications are cleaning wellbore/perforations, stimulating selective zones, controlling wells, milling/drilling
cement/tools/fish downhole, conveying tools in deviated/horizontal wells, gas lifting, setting cement plugs below production
packer, and many other applications.
Operating coiled tubing units in HPHT and ultra HPHT wells requires conformance of specific parameters for safety and
successful operations. Challenges of the operations and treatment design are exacerbated considering the environment
downhole. The conditions become more severe in ultra HPHT environment if the well is deviated or approaches horizontal.
Intervention and treatment in ultra HPHT and in highly deviated or in horizontal wells requires special procedures,
techniques and tools. The requirements include modified procedures as well as equipment and products to withstand the BHST
temperatures for the entire operation.
As an example of complications in HPHT wells, on the east coast of India, bottomhole static temperatures could go as
high as 507°F and mud weight could vary between 14 and 19 ppg in deviated wells. Experience has shown that conventionally
calculated bottomhole circulating temperature alone is inadequate to determine the working temperature downhole. However,
with the help of computer-aided temperature simulation and all the above techniques, many successful CTU operations have
been executed under these difficult conditions.
Using case histories for illustration, this paper will share best practices developed from 4 years of successful interventions
in HPHT and ultra-HPHT wells. These practices will include HPHT coil tubing intervention considerations, modified
procedures, special techniques and product choices.

Introduction
Coil tubing is being used by the oil industry for last 5 decades. As the technology advanced and operators are trying to
penetrate deeper for hydrocarbon and pushing and extending the boundaries, challenges exacerbated while reaching HPHT and
Ultra HPHT environment with safety and success. Drilling and production at east coast of India, especially at Krishna-
Godavary basin, often encounters high pressure and high temperatures. Reservoir pressure and temperature may go up to
18,000 psi and 507 0F respectively as estimated. So far the maximum pressure and temperature encountered for CT operations
were 13500 psi and 467 0F respectively at 5600 meter measure depth (5228m TVD) at KG basin. The case histories presented
in this paper are from the KG basin located at the east coat of India. The planning for the jobs started during April 2005 and
the jobs started executing from end of April 2006. The paper discusses on challenges encountered during the execution of
these HPHT coil tubing intervention operations in these deviated wells. For example, at the KG field, one well had BHT of
467 0F at a MD of 5602 meter, reservoir pressure was around 13,000 psi and the mud weight was 14.8 ppg. These extreme
well conditions had led to the variation in existing practices and development of modified techniques that made the operations
successful. The various jobs performed on this well were: 1) Perforation wash, 2) Matrix stimulation 3) Clean up & Fishing
job and 4) Abrasive Cutting of stuck pipe.
This paper illustrates on lessons learned during the design and execution of these jobs. There were some concerns on the
mud properties due to suffering of severe shearing inside small diameter CT, which is discussed and resolved in the paper
later. In addition, logistic and space restrictions challenges during the operations were also enumerated.

Well Intervention Planning Process Using Coil Tubing

For HPHT wells, extra care always requires to design a job. The process typically starts with the following steps for
designing and planning to derive the final recommendation and the execution plan:
2 SPE 126108

• Formulate and consolidate the objectives of the operations and expectations

• Collection of relevant data
• Validating the collected data – a double check found beneficial for the HPHT applications
• Assessing the resources
• Technical feasibility study for utilizing the available resources using the proper software simulator for CT
applications
• Collection of required and relevant samples of the wellbore and treating fluids/materials, products, etc.
• Perform necessary lab testing if applicable and assess the outcome
• Compare the results with the initial objectives and desire
• Recommending alternative equipment, products and/or process

As the job is being called and the objectives consolidate, the relevant well data is being collected. For the HPHT
application, one more extra step is being practiced to validate the collected data since the bottom hole conditions are extreme
in nature compared to the conventional wells. The primary and most important consideration in the design process is to run in
and pull out the CT from the well safely and undamaged. During data collection process, error can lead to the failure and even
catastrophic consequences in these extreme conditions.
The available data is then being feed in to the tuned software to simulate the job and obtain the boundaries and limitations
of the operation. Extensive simulation by the properly tuned software is proven to be essential. Available resources are the key
components to consider. Then all the available resources are being assessed to ascertain the workability of the resources within
the boundaries and limitations with sufficient safety factors. If any fluid is being planned to pump down the hole, also being
sampled and tested in the lab for its effectiveness and compatibility with all other well bore fluids and formation fluids it may
encounter.
The next part of the planning process embarks into the final stage of forecasting the outcome of the operation by utilizing
the tuned simulating software extensively. As far as the coil is concerned, operating limits degradation due to high
temperature, elongation due to temperature (thermal expansion) and tensile stress (due to length of the coil hanging or from
other sources), collapse rating degradation due to high temperature and elongation, collapse due to high well bore pressure, in-
situ fatigue induced by the corrosive gases, etc., being simulated extensively. For example, in the Case History I, thermal
elongation was around 11 feet and stress elongation was around 6 feet during RIH and around 8 feet during pull out, in total 19
feet elongation the CT suffered. The circulating temperature along the well bore also not linear. After simulating the
temperature along the well bore, it was observed that the hot spot exists far above the end of the CT. Figure-13 illustrated the
temperature profile along the well bore as predicted from the temperature simulator. It could be seen that the hot spot of the
temperature was around 600 meter above the bottom. As a result, it is not the bottom part of the CT suffered the temperature
most; it is way above the bottom suffered the temperature degradation of the CT strength. After extensive simulation, the
operating limits/boundaries are being established and feasibilities of the job assessed. The results are compared with the initial
objective desired. Afterwards recommendations are being made for any additional requirement (resources and materials) to
execute the jobs in best possible ways.
Moreover, the challenges often emerge from logistics rather than designing. For an Ultra HPHT job, the required coil
posses thicker wall thickness and longer length compared to the conventional coils, which in turns exhibit weight of 25 MT to
45 MT depending on the CT size. Many cases the cranes on the offshore rigs have limitation of capacity, i.e., 25-30 MT. Due
to the properties of the CT for these jobs, the gooseneck also requires extended and this provide additional obstacle to enter
thru the V doors. Many times it requires parting the gooseneck from the injector head to make it enter thru the V door. Figure-
1 illustrates a typical CTU assembly for better understanding the rig up.

General Information/Setup for the Case Histories:

• The case histories described in the subsequent sections were the first four in the campaign and encountered most
challenges. The lessons learned from these jobs were applied to the subsequent operations later on. Author felt that these
initial stories will help to appreciate the process developed for such extreme operations for the next generations. On the
course of time, these were further developed and became matured.
• All the above jobs illustrated in the case histories were on a jack-up rig.
• The depths were correlated mostly by tagging the hold up depth and also by Tubing End locator.
• There were always two pressure barriers in the rigged up stack for all the operations.
• The detail of the rig-up and the well control barriers were not described in this paper since previous papers already have
sufficient details.
• The whole system was rated to 15 kpsi.
• Details of the fluids, i.e., recipes and properties of stimulation or washing or other fluids, also not provided in this paper
since the focus was kept for CT operations.
• The string fatigue information while operations were being recorded and input in the simulator for the next operations.
SPE 126108 3

Case Histories:
As mentioned above, the 1st such well was drilled in the KG basin and had a depth of 5602 meters MD with a ‘S’ profile
having 29.4 deg maximum deviation. Figure-2 & Figure-3 illustrate more detail about the well. It was drilled with 14.8 ppg
water based mud and cemented at a temperature of 467 0F. Afterwards 3-1/2” DST string was run to test the well. The
reservoir was tight sandstone gas bearing with high condensate ratio. It was perforated and tested in 14.4 ppg calcium bromide
brine. The four jobs, mentioned in the ‘Introduction’ were performed in this well. Selection of the appropriate equipment was a
good challenge. Below is a brief list of the major equipment used for the jobs.
1) The 1-1/2 inch coil string had length 5710 meter, thickness varied from 0.156 to 0.175 inch having 80,000 psi yield
strength, internally tapered, was hydro tested at 15,000 psi after manufacturing, 2) heavy duty injector with extra pull
capability, 100 kLbs 3) quad BOP of 15 kpsi, 4 ) dual stripper assembly, 5) 15 kpsi riser and connector and fully automated
control cabin and heavy duty power pack with/and 6) all other valves and accessories.
Selection of coiled string is always a crucial challenge for the HPHT or ultra HPHT environments due to the reduced
collapse resistance caused by the temperature and elongation. Since stronger injectors are being used, the coils are more
susceptible to the ovality development and hence the collapse rating reduces more. To overcome these challenges, a thorough
premonition was sketched with all possible worst case scenarios. The best size of the CT could be 1-3/4 inch or bigger, but
there was a crane limitation to lift the 5700 meter coil tubing on the rig. Thus 1-1/2 inch size of the coil was selected.
Including all these considerations, tubing force analysis was performed utilizing the computer aided simulator to optimize the
coil tubing size, strength rating and wall thickness accordingly. These differs from the thumb rules industry practices.
Application of the accurate computer simulation provided a huge flexibility and perfections to the design and selection of the
equipment.
As a consequence, the injector head also to be capable of handling this heavy coil tubing with sufficient margin. The
stripper generally suffers from high temperature. Though high temperature rubber elements are also available for these
strippers, it is always good to have a cooler before the stripper so the longibility of the stripper increases. The power pack and
all other related equipment also should be capable of handling such high temperature and load. The details are enumerated in
the individual case histories below.
The major challenges were:
- The reservoir pressure was over 12500 psi, the brine (well bore fluid) weight was 14.4 ppg and the BHT was 467 0F at
the TD and the temperature was 400-450 0F for the CTU operations around the testing objects.
- Space restriction for rigging up pressure control equipment and the Injector Head on the rig floor in a conventional
manner.
- Obstruction caused by the presence of low height V door.
- It was a new operation for the operator on that rig. Innovation for both CTU and Rig crews involved together in an
operation of these profiles for the first time. The jobs were performed close to the CTU design/operating limits.

Case History I: Perforations Wash Job

After the well was perforated at 5350 meter, it was decided to perform a wash job around the perforations due to the
operator suspected that the perforations were blocked by debris as there was restricted inflow. A washing BHA was run having
a wash nozzle. More efficient tools were also available in the market, but were not available in the inventory. The following
major challenges were encountered during execution of the job:
Design Challenges:
The main challenge was limited and fixed inventory. Further mobilization could take months and rig had to wait. As
the brine weight was 14.4 ppg calcium bromide, the viscosity of this brine did not allow enough flow rate thru the CT
within the operational limits to make the wash efficient. Extensive simulations were run to optimize the design. Seawater
was finally selected as the medium. Again, due to high formation pressure and heavier brine outside of the CT made the
string susceptible to collapse. The design was proposed and the job was executed at very close to the CTU operating limits.
The tubing force analysis during running in and pulling out for this job are shown in Figure-5 & Figure-6. As it could be
seen from both the plots, near bottom, the CT was pretty close to the limits.
Operational Challenges:
One of the major challenges was the space constrain while rigging up pressure control equipment and injector head on
the rig floor. The job was performed during testing phase and the deck space was very tight to spot the necessary
equipment. In addition, there was obstruction created by the height of the V-door. This caused the initial rig up to take very
long. The low height of the V-door presented a significant challenge, which was overcome by rigging up the injector inside
the derrick and then mounting the gooseneck. The Rubber Gasket on the Reel-Entry was pre-job tested to 10,000 psi, but
was not able to hold the pressure in the middle of the job at these high pressures for long. During changing this gasket,
difficulty encountered to reach near the gasket due to its location. After this experience, it was planned to place a “Tee” on
the Reel Entry to facilitate the easy change of the components around.
Results:
Though there were issues related to the limited rig space and rubber element changing during the job, the CT operation
were executed smoothly as planned without any CT failure and the objectives of the perforation wash were achieved as
expected.
4 SPE 126108

Case History II: Matrix Stimulation Operations

This job was performed on the upper object. During the drilling phase, water based mud was used and the operator was of
view that the zone possibly damaged due to the drilling fluids filtrate invasion / water blockage etc. Stimulation could be
required in order to remove the near wellbore formation damage and to check the true potential. Low Surface Tension Fluid
Recovery Cocktail treatment was proposed.
Considering the current inventory of the stimulation chemical, a formulation was proposed comprising of blend of solvents
and surfactants, flow back agents and KCl. No test on the proposed system was possible due to unavailability of the formation
sample. However, since the formulation was contingent, and these products generally did not cause any apparent / evident
damage during stimulating a previous well, the system as formulated was proposed. The object of testing was a tight gas
bearing sand with reservoir pressure up to 11800 psi.
Design Challenges:
As a result, the treatment program was prepared for perforation wash / near bore damage removal with the above
mentioned solvent & surfactant blend. Considering the past injectivity information and anticipated permeability of 0.05-
0.001 mD, it was anticipated that high pumping pressures would be required. These limited the use of the CT since the
pressures over the gooseneck could exceed 9,000 psi (for static coil). The BHA used were consist of i) Dimpleon
Connector, ii) Check Valve, iii) Hydraulic Disconnect Tool, iv) Sequence Valve, v) Motor Head Assembly, vi) Straight
Bar 1.75”, 5 ft long and vii) Jet Nozzle 1.75 inch, with down and side facing ports.
The main challenges were to maintain the CT inside pressure to resist collapse due to heavier fluid was out side along
with the high formation gas pressure. A sequence valve was introduced in the BHA to keep excess pressure inside the CT
so that the differential pressure remains below 1000 psi collapse pressure. Also during washing, the pipe over the
Gooseneck kept static so that the CT burst pressure remains below the limit. The tubing force analysis is plotted in Figure-
7 & Figure-8.
Operational Challenges:
It remained challenged to spot all the equipment and the rig up. Also additional precautions were put in place due to
high pressure Gooseneck operations. The job had no other problems operationally and went smooth.
Results:
The CT was ran in and pulled out without any problem. The stimulation was effective as observed from the production
increased. It would have been better if acid could have used to stimulate.

Case History III: Clean up and Fishing

It was the same gas bearing formation in the same well, which was under testing. After finished testing the zone, the DST
string found stuck in settled barite outside the tubing. Several attempts were made to free the pipe. Finally the string was cut at
4500m by a chemicals cutter. But the cutter (RCT) itself was dropped unfortunately and became fish and hindered to the next
zone testing operations since the zone top was below the fish. Altogether, there was 7.5 feet long RCT fish at 4760 meter along
with a 1.56in HSD perforating gun (10 feet long) fish at 5180 meter.
This job was called for replacing/jetting the existing 14.4 ppg mud from the DST string with slicked seawater followed by
replacing the seawater by 14.4 ppg CaCl2-CaBr2 brine. Then push the fish down for facilitating the further operations for
retrieving the rest of the tubing.
Design Challenges:
Initially the operator wanted to execute the operations using the mud. But it was a concern on the stability of the mud at
BHST of 300-430 0F inside the CT. The friction pressure expected from the mud circulation thru this CT at a desired rate
was exceeding the stress limits of the CT. Using the CT simulator, it was found that less than 0.2 bpm flow rate of mud
could be achievable within the safe operating limits of the CT, which was insufficient for the operations. Also the mud
could suffer very high shearing inside the CT and could de-stabilize on the way. After running the CT simulator
extensively, found brine to eliminate the above mud instability and increase the flow rate during the operation.
The next challenge was to push the fish down. As it could be seen from the TFA plot in Figure-11, there was not much
room available to push the fish down due to the friction lock limits. Since the well was deviated, generally the CT is
susceptible to friction locks more as the deviation increases. The techniques used was 1) reduce the metal to metal friction
in the well bore by using friction reducer, 2) slick the fluids around, 4) extra weight at the CT end by placing a straight
weight bar in the BHA and 5) extensive software simulation for various scenarios to reduce the friction lock limits.
Operational Challenges:
During these operations, fours hours of rig downtime were seen due to miscommunication between the rig personnel.
In addition, a forceful decision of using a different rating crossover was imposed due to the missing of the Flowhead,
which was sent back to the base in between the operations. This was a locally made cross over and was not tested properly
except a hydro test. But during the job, crack was developed on its body and started leaking. This again established that
properly certified equipment need to be put in the high pressure operations.
In fact, the operator insisted to start the job using the mud, which was available on the rig, due to the unavailability of
sufficient quantity of brine onboard and the cost involved due to brine wastage. But at a rate of 0.15 – 0.2 bpm, the
pressure shot up to 9000 psi and then had to switch to brine. Meanwhile the rest of the brine was prepared. This once again
validated the CT simulator accuracy.
SPE 126108 5

Results:
Other than the above difficulties, the job went as planned. The mud was replaced and the fish was pushed down to the
hold up depth and made clearance for further operations. The CT pulled out successfully.

Case History IV: Abrasive cutting of Tubing

It was again the same zone in the same well mentioned above. The tubing, which was left in the well after the chemical cut
at 4500 meter, was still a hindrance for testing the next zone. It was decided to cut the 3-1/2” tubing below the depth 4774 if
possible. After analyzing various options and existing limitations, abrasive cutting was recommended for the purpose
considering a BHST 430 0F and at a depth 5100 meter if the tool could go. The abrasive cutting tools were fit for those
conditions. The tools were to run on CT to depth and 100 mesh sand slurry was to pump thru the cutting tools at 0.5-0.75
bbl/min to achieve the cut.
Design Challenges:
The critical part of the job was to obtain a minimum flow rate of 0.50 bbl/min to achieve the minimum cutting velocity.
The well control during this cutting operations and the limitation of the CT were also very challenging. Considering these
critical conditions, the CT simulator used numerous times. 14.2 ppg gelled brine was proposed to carry the sand from the
surface equipment and to keep control on the well. Also this system was able to provide a minimum flow rate of 0.5
bbl/min, which was critical for achieving the minimum cutting velocity by the sand. The program was prepared
accordingly and proposed for abrasive cutting of the tubing at 4774 meter, which was 5 meter above the RCT fish. Before
the job, wireline run confirmed that the tool can not go below 4774 meter due to obstruction. TFA analysis was shown in
Figure-11 and Figure-12. Three major indications were expected when the cut would be completed: 1) Flow could be
observed from annulus if the cut was above the settled barite, 2) some barite from the cutting point could enter into the
tubing and subsequently carried to the surface and could be visible or 3) cutting head would be eroded more than the
tubing ID by the reflecting sand. Either one of the first two would confirm the completion of the cut while the CT in the
well. Since the string was stuck inside barite, it could be difficult to observe the 1st indication. The 3rd indication could be
only visible after the BHA would be pulled out on the surface. Including all other necessary component, 1.70 inch OD
Motor Head Assembly, 2.0 inch OD Abrasive Cutting Head and 1.7 inch OD motor were made up in the BHA.
Operational Aspects:
Preparation of the gelled brine was little delayed. Otherwise the job went smooth as per the plan. The CT was run in
and pulled out successfully. It was concluded that the cut was made based on the third indication. The eroded cutting head
has shown in Figure-4.
Brief Job Procedure:
The motor was tested at surface at 0.3 BPM - 0.8 BPM and pressures were recorded before run in the hole. The BHA
was run in the hole and circulated with 14.2 ppg brine. When reached the cutting depth at 4774 meter, the brine rate was
increased to the maximum and pumped for 30min to get all movement out of coil tubing. The brine rate was slowed down
to 0.5 bbl/min, pumped around 5 bbl with sand (concentration ½ lb/gal) and then started pumping sand at concentration of
1.0 lb/gal in 10 bbl of sand slurry, lastly followed by 11.6 bbl of brine. The 11.6 bbl brine helped the sand to push to the
bottom of coil and initiated the cut. Once the sand reached the bottom of coil, the rate was increased to 0.75 bbl/min till the
cut was completed. This took around 30 minutes and once the job of cutting was completed, brine was circulated for 10
min at 0.4 bpm and CT was pulled out.

Operational/Technical Learning
• Detailed job planning by an experienced hand can make the operations and meet the objectives more efficiently and
reduce the operations timing.
• Experienced operations hands are also important and crucial to achieve the objectives efficiently for the HPHT
operations.
• Modular CTU equipment provided better rig space management for the offshore applications.
• The operations would be more flexible if bigger size of the CT could be used.
• The abrasive cutting job was used first time in India. As the earlier attempt to cut the string by chemical cutter at the
required depth was failed due to very high temperature, the “Abrasive Cutting” job was found suitable for the
purpose. During the job, a minimum of 0.5 bbl/min to 0.75 bbl/min flow rates were maintained to have the maximum
cutting velocity.
• Another factor was very essential to these HP/HT wells, was to maintain the density of sand carrier fluid, i.e., gelled
brine at 14.2 ppg at bottom of the hole.
• Logistical challenges exhibited more dominating then technical in many instances/cases. Thus during the planning
phase, pre-feasibility study to be performed and required arrangement to be made for saving rig time.

Conclusion
- The objectives for each of the interventions were achieved
6 SPE 126108

- The CT was run in and pulled out successfully based on the method adapted, i.e., tune and use the CT simulator
extensively for various options and scenarios to optimize the operations
- The abrasive cut was successful, which was evident by the pressure communication inside and out side of the tubing.
In addition, there was presence of barite in the returns indicating the same. (Note: tube was stuck in barite).
- Due to the ultra HPHT conditions (>350 0F), collapse pressure rating reduced substantially compared to the
conventional operations
- After these jobs, for last four years, the CT was being applied successfully to intervene these type of HPHT wells
- It was possible to achieve the successes using CT having less OD and less wall thickness compared to the HPHT jobs
were performed around the North Sea using 1-3/4 inch OD CT. The operator was financially quite benefited using
lower specification of CT for the higher degree of HPHT environment and using less deck space.

Acknowledgements
Thanks to BJ Services for the permission to publish this paper. The views and opinions expressed are solely by the author and
do not necessarily reflect those of any of the companies involved. Also thanks to the below personnel for their extended help
and contribution to the success:
1. Robert Proctor – BJ Services
2. Damian O'brien – BJ Services
3. Samir Kale – BJ Services
4. Henry Leigh – BJ Services
5. Greg Dean – BJ Services
6. Matthew Barrett – BJ Services
7. Jose Moniz – BJ Services
8. Ronnie Ogg – BJ Services
9. Ronny Weible – BJ Services
10. Carlos Aguilera - BJ Services
11. Wallace Walters - BJ Services
12. Stan Loving – Thru Tubing Solutions
13. Kim Marmon – Thru Tubing Solutions

Nomenclature
API > American Petroleum Institute
psi > pounds per square inch
kpsi > thousands of pounds per square inch
MD > measured depth
TVD > true vertical depth
CTU > Coil Tubing Unit
CT > Coil Tubing
bbl > barrel
ppg > pound mass per gallon
BHT > bottom hole temperature
BHST > bottom hole static temperature
BHCT > bottom hole circulating temperature
HPHT > high pressure high temperature
HT > high temperature
TD > target depth
SOBM > Synthetic oil based mud
BHA> bottom hole assemblies
OD > outside diameter
DST > Drill Stem Test
RCT > Radial Cutting Torch
HSD > High Shot Density
in > inch
MT > Metric Ton
kLbs > Kilo pounds
BOP > well control Blowout Preventor
RIH > run in hole

References:
David Stiles, Mark Trigg: “Mathematical Temperature Simulators for Drilling Deepwater HTHP Wells”, paper SPE/IADC-105437,
presented at the 2007 SPE/IADC Drilling Conference in Amsterdam, The Netherlands.
SPE 126108 7

Syed Haidher, Samir Kale, Sami Affes, Suresh Kumar: “HPHT Cement System Design - East Coast Case History”, paper SPE-104048,
Presented at the 2006 IADC conference in Mumbai, India.
Coil Tubing Operations and Procedures Manual – BJ Services

Figure-1 Figure-2

Figure-3 Figure-4
8 SPE 126108

Figure-5 Figure-6

Figure-7 Figure-8

Figure-9 Figure-10
SPE 126108 9

Figure-11 Figure-12

Figure-13