SPE-205634-MS
Hazirah Abdul Uloom, Asba Madzidah Abu Bakar, M. Mifdhal Hussain, Fuziana Tusimin, Zaidi Rahimy M. Ghazali,
M. Sharief Saeed Salih, M. Fakhrin A. Rasid, Sunanda Magna Bela, Latief Riyanto, M. Hafiz Othman, Syazwan A.
Ghani, and Nurul Aula A'akif Fadzil, PETRONAS
Copyright 2021, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition held virtually on 12 - 14 October, 2021. The official
proceedings were published online on 4 October, 2021.
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
Based on the production data from first development campaign in 2017, contamination reading of CO2
and H2S from gas production wells were observed increasing from 3% to 10% and from 3ppm to 16ppm
respectively within one year production. These findings have triggered the revisit in 2019 development
campaign optimization strategy in terms of material selection, number of wells, reservoir targets, and
completion design. Thus, tubing material was upgraded to HP1-13CR for the upper part of tubing up to
10,000 ft-MDDF (feet measure depth drilling rig floor) to avoid SSC risk due to the geostatic undisturbed
temperature is less than 80 deg C, however the material of deeper tubing remains as 13CR-L80 as per
2017 campaign. Moreover, the mercury content from first campaign was observed to be above threshold
limit from intermediate reservoir based on mercury mapping exercise done in August 2018.As the mercury
removal system is not incorporated in the surface facilities, the mercury reading from the well in the 2019
campaign need a close monitoring during well testing so that appropriate action can be taken in case the
recorded contaminant reading is high. Dedicated zonal sampling plan to be performed if the commingle
zone (total) mercury reading was recorded to be above the threshold limit, and that zones will be shut off
to preserve the surface facilities.
Opportunity was grabbed to optimize number of wells by completing both shallow and intermediate
sections in a single selective completion to maximize the project value. However, this combination will
lead to major challenges during operation due to the huge difference in reservoir pressure and permeability
contrast in each perforated reservoir as the required overbalanced pressure of completion brine for shallow
reservoir is much lesser than the requirement for the mildly overpressure intermediate reservoir. Thus, a
potential risk of severe losses and well control is present at shallow reservoir. To mitigate this risk, loss
circulation material was pre-spotted in the TCP (Tubing conveyed perforation) BHA prior to fire the gun
to allow for self-curing process should losses take place.
During the first development campaign, the completion tubing was running in hole in two stages. The
lower completion was deployed via drill pipe and the perforated zones was secured with fluid loss device
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678 Challenges of Well Completion Design & Operation Solutions for Deep
Gas Well with Multiple Producing Zone in Mildly Overpressured Reservoirs
at Offshore Malaysia
2
SPE-205634-MS
Introduction
T field is a non-associated gas field situated in offshore Malaysia at a water depth of around 140ft. It
is approximately 6 km by 3 km in areal extent, is a faulted rollover structure in a deltaic setting. Gas
accumulation in the eastern part of the area is trapped by a three-way dip closure located on the downthrown
side of the NE-SW (North East- South West) trending West growth fault. The western part of the field is a
one-way dip closure truncated by the West fault and the North growth fault.
T field consists of 68 stacked reservoirs with independent fluid contact. The reservoir depth ranging
from 8,000 to 16,000ft which being grouped into three reservoirs, Shallow, Intermediate and Deep. This
paper will be discussing on Shallow and Intermediate reservoirs as those were being completed in 2017
development campaign, which second campaign is being focused. Shallow and intermediate reservoir for
T field were developed in two campaigns to maintain the production plateau to meet the gas sales demand.
Total of five wells were drilled through first development campaign in 2017 where two wells penetrated
from shallow reservoir, two wells penetrated intermediate reservoir and one well penetrated both shallow
and intermediate reservoir.
T field was further developed in 2019 during second development campaign, tapping on shallow and
intermediate reservoir produced commingle from both reservoirs. Planning and execution of the campaign
was optimized post 2017 development campaign utilizing updated reservoir information. Originally, four
wells were planned to be drilled in 2019 campaign as per FDP program. Well number, design and planning
were optimized and resulted in three wells successfully being drilled and completed for 2019 campaign.
For 2019 drilling campaign, target reservoirs are as follow:
Table 1—Summary of main reservoir section
Main Reservoir Sections
Reservoir intervals/Formations covered
Depth (ft TVDSS- feet total
vertical depth subsurface)
Shallow
T600- T800 reservoirs
8,600-11,300
Intermediate
T810-T831 reservoirs
11,350-13,400
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located between lower completion tubing and gravel pack packer. The upper completion tubing was then
deployed and tied back to the lower completion packer. This approach was applied as mitigation to prevent
fluid losses and to ensure the tubing can be safely deployed to the intended final depth. However, based
on the actual performance and losses rate data during the first campaign, the completion design in second
campaign was optimized and deployed in single stage. Since shallow and intermediate reservoir were
combined in multiple production zones where five SSD (Sliding Side Door) were installed, the slickline
option to set packer was waived due to the risk of setting tubing plug in deep wells. Pump out plug was
considered as an option but then dropped due to high hydrostatic pressure. The packer setting pressure was
too close to plug shear pressure. Therefore, a self-disappearing plug was utilized as it did not require any
slickline intervention and can be ruptured by pressure cycle. With this option, risk of pre-mature rupture
of plug was eliminated.
The paper will discuss in detail each challenge mentioned above together with details calculation that
was performed throughout evaluation and selection processes prior best solution being selected as these
optimizations resulted in nearly three days saving of rig time, contributing to 2.6% of well cost reduction and
the required number of wells were optimized to be three instead of four wells. Moreover, a safer production
life of wells by selecting a suitable tubing material and eliminating the risk of mercury production above
the above threshold limit.
SPE-205634-MS
3
Statement of Theory and Definitions
Table 2—Summary of expected contaminant
Reservoirs
CO2 (%)
H2S(ppm)
Hg gas (ug/Nm3)
Hg condensate (ppb)
Hg water (ppb)
Shallow
3
5
<5
<10
<40
Intermediate
10
16
<10
500-1000
40-60
Note:
• Above readings were based on sampling done.
• Mercury reading was taken from condensate phase. Higher mercury content from intermediate reservoir wells
Based on the findings, optimization is conducted to maximize drainage from shallow and intermediate
section via three wells versus four wells, which improves the gas recovery to be achieved as compared to
initial plan. Summary of major changes for second campaign include:
•
•
•
•
•
Well's number: wells number are reduced from four wells to three wells
Well's location: new drainage area was identified in western area to increase the recovery due to
increasing shallow GIIP (Gas Initially in Place) based on 2017 drilling data.
Reservoir targets: all three wells were produced commingle targeting both shallow and intermediate
reservoirs.
Casing schematic design
Completion design
Completion design in the first campaign was rather more conservative with more mitigation measures in
place due to huge uncertainties of the reservoir properties and parameters. Having said that, the completion
tubing trip was segregated into two parts. The first part was to cover the entire zone of interest where the
lower part of the tubing was hanged using gravel pack packer connected to ball type fluid loss valve below
it and it was conveyed to the target depth via drill pipe. Once the drill pipe is pull out of hole, the upper
portion of the tubing then was ran in hole sting into the seal bore at the gravel pack packer to tie back the
completion tubing. By doing this, it is more confident to safely complete the well as the reservoir section
with high permeability value has been isolated. Below table illustrates the pressure range for each reservoir
as measured during drilling operation:
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Post 2017 campaign, there are few key subsurface findings majorly in structural, depth, targeted reservoirs
and some other finding is observed that it is expected within the uncertainty range. However, collected data
from the first campaign showed that there is a suspected early high-pressure ramp below T830 reservoir
which is different from other offset wells where high pressure ramp is only encountered deeper than T835.
Moreover, different contacts were observed in minor reservoirs in the eastern and western area. The structure
was observed deeper in the intermediate reservoirs section. In term of fluids properties, CGR (Condensate
Gas Ratio) at intermediate reservoirs is observed higher than initial assumption.
New data acquired on the first year of production has shown a severe of contaminants levels specifically
CO2 (Carbon dioxide) level which has increased from 3% to 10% and H2S (Hydrogen Sulfide) level from
3ppm (Parts per million) to 16ppm as well as high Hg (Mercury) reading in the intermediate section. This
has triggered the optimization of the development strategy that included number of wells, reservoir target,
type of completion and tubing material selection. The expected contaminants for shallow and intermediate
reservoirs recorded from first campaign during production phase was tabulated below:
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SPE-205634-MS
Table 3—Pressure range for each reservoir in 2019 drilling campaign
Actual Pressure Measured (Psia)
Shallow (minor) T773 – T793
3,800-4,800
Shallow (major) T800
3,700-3,900
Intermediate (minor) T810-T812
4,100-5,300
Intermediate (major) T820-T830
5,600-6,200
During planning stage for the second campaign, actual losses rate data from post perforation and during
ran in hole the completion tubing was gathered to evaluate the severity of the fluid lose risk. It was found
that the losses can be reduced to minimum acceptable rate and safely proceed after loss circulation material
is spotted.
Table 4—Historical Data on Losses at T Field in 2017 Campaign
Well
Max static loses rate (barrel/hour)
Max dynamic loses
rate (barrel/hour)
Cumulative loss during
completion (barrel)
A
30
70
313
B
60
100
703
C
350
40
316
D
30
7
159
Based on this actual historical data obtained from four wells, both completion design and operation
were optimized by converting from dual trips system to the conventional single trip system. This decision
however came with a notable challenge on the operation since it was also decided to combine the shallow and
intermediate reservoir in all three wells. This will lead to an exposure of huge difference in reservoir pressure
and permeability contrast in each perforated sand. The required overbalanced pressure of completion brine
for shallow reservoir is much lesser than the requirement for the mildly overpressure intermediate reservoir.
Thus, a potential risk of severe losses and well control will be a big operational challenge. Due to this main
concern, completion assembly was conveyed to intended depth in two separate runs in the 2017 campaign.
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Reservoir
SPE-205634-MS
5
Wells in T field were completed with long hole section up to 18,000ft well TD (Total Depth) and
long production intervals up to 2,000ft. The long hole section has led to undetermined success of runin hole the completion tubing to the target depth in a single trip with additional of challenging slickline
operation. Beside these two concerns, the long perforation intervals also possess risk of TCP (Tubing
conveyed perforation) gun misfire. Although two perforation trips can eliminate this risk, single perforation
trip was preferred and selected with additional bottom firing head system to provide redundancy on firing
mechanism. Below is an illustration of well trajectory for all three wells. Maximum inclination is 45 degree
and maximum well length is 18,095 ft. MDDF (feet measure depth drilling rig floor).
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Figure 1—Optimization of Well Completion Design from Dual to Single Run Completion
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SPE-205634-MS
Description and Application of Equipment and Processes
High H2S content together with the exposure of temperature has a significant effect on SSC (Sulfide Stress
Cracking) especially in low alloy steels as proven by few studies. In sour condition, with exposure of lower
temperature low alloy steel would not survive and has tendency to experience SSC. Material selection for
production tubing in 2019 campaign has much more focus on SSC. The main objective of tubing material
selection is to avoid any risk of cracking and corrosion in the tubing throughout entire well life.
Carbon and LAS (Low-alloy carbon steels) are the best option to be considered in material selection not
only from the economical point of view but also due to their availability in the market. Many initiatives have
been taken into consideration to increase the corrosion resistance of carbon and low-alloy steels. When the
environment is too aggressive for bare carbon steels, optimum option to minimize or eliminate corrosion
problems is the usage of corrosion inhibitors. However, under harsh and aggressive environment conditions
and high temperatures, more expensive materials, such as CRAs (Corrosion-resistant alloys) might be a
preferred alternative to be considered [1]. For production tubing design, the following table summarize the
plan FDP (Field Development Plan) vs actual optimized plan:
Table 5—FDP vs Actual Plan for Tubing Design
FDP
•
•
5-1/2", 20 ppf (pound per foot), 13Cr 80ksi
VAMTOP HC × 4-1/2", 12.6 ppf, 13Cr 80ksi, VAMTOP HC
Optimized Plan
•
•
•
5-1/2", 17 ppf, HP1-13Cr 95ksi, JFE Bear
5-1/2", 17 ppf, HP1-13Cr L80 JFE Bear
4-1/2", 12.6ppf, 13Cr L80, JFE Bear
HP1 grade tubing was located from surface down to 10,00ft MD (Measure Depth) tubing depth due to
SSC concern. Placement was decided down to 10,000ft MD is based on downhole temperature exposure.
The temperature exposure on the stated depth is less than 80° F where the tubing is exposed to the risk of
SSC. From 10,000ft MD to end of tubing 13Cr L80 tubing was remained as per FDP plan.
The mercury content from first campaign was analyzed to be above threshold limit especially from
intermediate reservoir based on mercury mapping exercise conducted in August 2018. Since the mercury
removal system is not incorporated in the surface facilities, the mercury content from the wells in second
campaign has been closely monitored during well testing operation. By having single selective completion,
zonal sampling is doable through shifting SSD (Sliding Side Door) open or close. In the event the mercury
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Figure 2—Illustration of Well trajectory with maximum inclination of 45 degree
SPE-205634-MS
7
Table 6—The Calculation for differential pressure at each reservoir section when using 10.49ppg (pound per gallon) brine
INPUT
OUTPUT
Density required
at surface (ppg)
Wellbore
Pressure when
using 10.49ppg
brine (psi)
Differential
Pressure (psi)
Sand
Depth (ft TVDSS)
Pressure (psi)
Density required
downhole (ppg)
T790-T793
11367
4778
8.31
8.57
6200.47
1422.47
T800
11929
5427
8.96
9.22
6507.03
1080.03
T808-T818
12692
5727
8.88
9.16
6923.23
1196.23
T820
12819
5090
7.84
8.13
6992.51
1902.51
T830
13290
6929
10.20
10.49
7249.43
320.43
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content recorded to be above the threshold limit, the high mercury content contributing zones will be shut
off to preserve the surface facilities and to be aligned within HSE (Health Safety and Environment) limit.
To further maximize project value, the FDP target of two wells were combined into one well as
single string and to produce as commingle. This is also to reduce the risk of shutting in one of the well
in case high mercury is encountered. In addition, since all the three wells in second phase penetrated
shallow and intermediate reservoirs, it is crucial to have good cement isolation between the two sections
because intermediate reservoir is suspected to have high mercury content in certain area of the field. Good
zonal isolation between shallow and intermediate reservoir allowed complete shut-off of the intermediate
reservoirs if it is found to produce high mercury content. For mercury content analysis, mercury content
in the produced fluid was observed to be higher than the measured mercury content during well test in
appraisal well. The contaminants have been included as part of monitoring parameters during unloading.
Completion design was optimized from dual to single run subsequently thorough analysis and study were
performed on offset well data from 2017 campaign. The result of analysis concluded that the losses occurred
exactly after perforating the formation is classified as instantaneous losses which then stabilized after short
period of time post perforation operation. However, the risk of losses still exists due to high overbalance
resulted from pressure variance of multiple zone (around 1,080 psi to 1,900 psi), detail of the overbalance
calculation as shown below:
8
SPE-205634-MS
This high differential pressure between reservoir inside wellbore becoming more significant during
wellbore cleanup operation where the entire well was circulated with low density 8.3ppg sea water until the
fluid properties met the required fluid cleanliness criteria NTU (Nephelometric Turbidity Unit) and TSS
(Total Suspended Solid). Highest differential pressure can be seen at reservoir number 4 where the value
will be 1,902 psi. Due to this concern, liner hanger packer inflow test was conducted prior wellbore cleanup operation to ensure liner hanger packer is holding and no communication exist between reservoir and
wellbore throughout the underbalance scenario during circulation with seawater operation.
For liner hanger packer inflow test procedure, WBCU (Wellbore clean-up) assembly will first be ran
in hole to liner hanger depth. Pipe ram is closed and kill line valve is opened for return fluid monitoring.
Calculated amount of base oil was first displaced into drill pipe to create underbalance condition inside
the wellbore. Pressure then locked inside drill pipe to prevent u-tube effect. Wellbore test packer was set,
and inflow test was conducted. Well was monitored through return fluid volume taken. Horner Graph was
plotted.
Horner concept stated that, if homogenous, radial flow is present in the build-up data, then a plot of
pressure versus the function log((T+dt)/dt) will resulted a straight line on this plot. As a result the interpreter
can extrapolate this straight line to the log (1) value on the time axis to get the pressure that would be derived
if the build-up were left for a certain period. The value of T is derived by summing all the flow times prior
to the build-up and is called the total flow time. The values of dt are derived by subtracting the elapsed
time from the initial start time to obtain the incremental delta time. "Horner" analysis may be used when
monitoring flowback or pressure buildup during an inflow test. [2]
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Figure 3—The Differential Pressure at each reservoir section when using
minimum 300psi overbalance brine against the highest reservoir pressure
SPE-205634-MS
9
Below is detail calculation for base oil volume required during inflow test operation. The same concept
was used for unloading operation where lighter fluid was displaced inside tubing to create required
drawdown to flow the well. Below are the parameters and detail calculation for lighter fluid displacement:
Table 7—Parameters used for liner hanger packer inflow test calculation
PARAMETERS
UNIT
VALUE
Required Under Balance
psi
1,000
Max reservoir pressure
psi
6,225
Required tubing pressure
psi
5,225
Total Depth
ft TVDDF (feet TVD Drilling Rig Floor)
12,588
Mud weight
ppg
12
Lighter fluid weight
ppg
6.8
X: lighter fluid depth
ft TVDDF
9,726
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Figure 4—Horner Graph was plotted during liner hanger packer inflow test operation
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SPE-205634-MS
For losses mitigation plan, LCM (Lost circulation material) pill was pre spotted 50 ft. above perforation
interval in the annulus before the gun is activated while at the same time sufficient LCM material was
prepared at surface as contingency in case losses rate increase beyond acceptable limit. Specific lab test for
LCM degradation test was conducted to identify suitable LCM. LCM ideally to remain intact throughout
completion operation and degrade right before well clean up and unloading operation. Two formulation
were tested on the lab using different LCM material which is Xanthan and Mudzymme. The main objective
of the lab test was to make sure the LCM remain intact throughout completion operation which is around 5
days and degrade before well cleanup operation. Below are the lab test results for LCM degradation test.
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Figure 5—Liner hanger packer inflow test calculation
SPE-205634-MS
11
Table 8—Degradation test result for Xanthan + completion fluid
TEST
UNITS
BHR (Before
Hot Rolling)
PERIOD AGED
Days
–
1
2
3
4
TEMPERATURE
°F
–
280
180
180
180
pH
–
9.2
9
9
8.8
8.8
PLASTIC VISC.
cP
23
22
22
18
18
YIELD POINT
lbs/100ft2
43
41
41
41
41
5%
5%
5%
5%
Table 9—Degradation test result for 10% Mudzymme + completion fluid
TEST
UNITS
BHR (Before
Hot Rolling)
PERIOD AGED
Days
–
1
2
3
4
TEMPERATURE
°F
–
280
280
280
280
pH
–
9.1
9
8.7
8.7
8.7
PLASTIC VISC.
cP
21
17
16
15
15
YIELD POINT
lbs/100ft2
40
36
35
35
35
10%
13%
13%
13%
Degradation %
AHR (After Hot Rolling)
Based on the lab test result, both Xanthan and Mudzymee can remain intact within five days (plan
completion operation day). However, degradation period of Xanthan was relatively slower comparing to
Mudzymme which may lead to the risk of well unable to be unloaded on time as per plan. Therefore,
Mudzymee with 10% concentration was selected for LCM material.
In the optimized single trip completion design, ability of the completion tubing to reach target depth and
pull out of hole (if required) was evaluated thoroughly via T&D (Torque and Drag) analysis. For both cases
slack off friction factor ranging from 0.1 to 0.5 were applied. The result as below:
Figure 6—Result from Torque and Drag Simulation
Result showing running parameter within acceptable limit for all RIH (Run in hole) cases where all hook
load cases simulated none of them exceeding maximum yield and no buckling issue can be seen when RIH.
For POOH (Pull out of hole) simulation, hook load during POOH was exceeding maximum yield of the
tubing at higher FF (Friction Factor) 0.4. However, this is not a major concern as FF inside casing is usually
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Degradation %
AHR (After Hot Rolling)
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SPE-205634-MS
Figure 7—Optimized plan for TCP set-up
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ranges between 0.2-0.3. After thorough discussion on this matter, it was agreed to proceed with optimized
design of single run instead of dual run.
Due to significant non-productive time related to slickline operation in previous historical wells, packer
setting operation against slickline plug option was re-evaluated. This risk is major threat in these three wells
due to the deeper well depth. High overbalance brine weight is expected to give impact in more challenging
slickline operation. Thus, the option to use slickline plug was waived and intervention-less alternative option
was identified. POP (Pump out Plug) was the next available option that can met the purpose at lowest
price, but due to high hydrostatic pressure where the packer setting pressure was found to be too close to
pressure to shear the pin at the POP. Therefore, a self-disappearing plug was selected and utilized as it did
not require any slickline intervention and can be ruptured by pressure cycles. With this option, risk of premature rupture of plug was eliminated.
Perforating strategy was scrutinized to make sure the whole production section able to be perforated in
single run while making sure safety is prioritized. TCP (Tubing Conveyed Perforated) gun configuration
was improvised to cater long interval gun length. The gun was configured with top and bottom firing head to
make sure gun fire 100% and eliminate the risk of gun misfire. Furthermore, for safety reason the company
internal standard, does not recommend bottom firing head ensuring the personnel will never be exposed to
an armed gun string while making up, running in or pulling the gun out of the well. Due to this concern,
DID (Detonation Interruption Device) was installed at the bottom firing head as safety feature to prevent
gun premature activation while making up the gun connection at surface. This safety device consists of a
eutectic metal that protects the initiator from the firing pin at normal surface conditions. DID consist of
eutectic metal that has a very low melting point, which will remain it in a solid state and stop the explosive
signal from being transmitted to the perforating assembly even after the firing head has been triggered.
The eutectic metal has been selected based on minimum BHT (Bottomhole Temperature) of the well. In
the condition where DID is exposed to normal surface temperatures, the eutectic metal will remain in solid
state until the TCP assembly is run in the hole. When it reaches intended reservoir section and exposes to
intended heat at BHT, the eutectic metal will liquified and enable the transformation of explosive signal
from the firing head to the perforating assembly. In the case where the guns misfired and are pulled out
of the hole, the metal will return to solid state when it is exposed to the lower temperatures as it is away
from reservoir condition. This mechanism will helps preventing accidental firing of the guns at unintended
depth and condition.[3]
SPE-205634-MS
13
Presentation of Data and Result
Despite of multiple challenges throughout the operation, all optimization and improvement plans had
resulted in:
Mercury reading was confirmed during well unloading and testing operation. The measurement of the
contaminants content was included as part of the well unloading objectives. The confirmation was done in
real time with temporary well test package since the well was yet to be tied into the permanent facilities. It
is important to record the data during the well open-up so that proper baseline data can be captured prior
handing over the well to Production Team for further monitoring exercise. By implementing this as well,
it will confirm the mercury presence and reading so that proper HSE measures can be taken during the
flowline tie in and subsequent operations.
Based on the testing performed, two of the wells in second campaign exhibited considerably low levels
of Mercury and CO2 concentration. Relatively higher levels of CO2 were observed in another one well with
an average of 6.6 mol% which is higher than the other wells but still lower than the levels recorded during
first campaign unloading data which had CO2 level of around 8%. Relatively higher levels of mercury were
also observed in this one well. The main insight from the executed drilling campaigns in T field is that
contaminants seem to be concentrated in the Eastern part of the reservoir, that could possibly be due to
localized charging system or different source rocks, regardless of the cause, focused monitoring efforts is
required in this region of the field.
Below table summarizes the mercury monitoring during well unloading, which no zone shut off was
decided to be done during the drilling campaign to avoid premature shut off. Further monitoring was
conducted especially for Well-3:
Table 10—Mercury result during unloading
Well
Mercury in Gas (ug/m3)
Mercury in Water (ppb)
Mercury in Condensate (ppb)
Well-1
4.5
8.22
41.27
Well – 2
9.10
4.63
9.53
Well – 3
8.42
30.57
501.4
Post well unloading and testing, proper and cautious monitoring plan was established together with
production team and frequency of further sampling and testing was redefined. This is to ensure any
contaminants spike during production life can be recorded with necessary action to be taken.
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1. Successfully set packer against intervention-less plug that help to avoid potential three additional days
to run slickline as contingency for pump out plug.
2. Successfully optimizing completion design from dual run to single run that have led to time saving
of 2.8 days.
3. Successfully perforated 2,168 ft. net perforation interval in one single run for each well with TCP gun
100% entirely fired. Operation have been conducted safely without any incident of gun misfire with
implementation of DID that reduce the risk of gun firing while making up the gun connection.
4. All three wells in 2019 campaign were successfully completed and flow at production rate 5-11%
higher than target.
14
SPE-205634-MS
Table 11—Monitoring plan for contaminant in T field
No
Plan
Method/Equipment
Mercury re-mapping & monitoring
for all phases (gas, condensate,
water)
•
Objective: Re-mapping at
Mini test separator offshore and
wellhead up to terminal and
speciation test in lab onshore
speciation (spot sampling is
not conclusive)
Strategy: To be done post well
stabilization
CO2 & H2S Monitoring
2
Dragger tube
•
•
Mapping/ speciation depends
on production changes and
anomalies found at export line
If no issue found, to be
conducted once a year
Daily basis at export line
Conclusion
This paper had discussed multiple optimization plan to manage all the challenges in well completion design
and operation as solutions for deep gas well with multiple producing zones in mildly overpressure reservoirs.
Tubing material selection was optimized to mitigate SSC risk, production packer has been set against
intervention-less plug as an alternative of running slickline plug, completion design was optimized from
dual run to single run, perforation operation has been done safely without any incident of gun misfire
with implementation of DID and all three wells were successfully completed and flow at production rate
higher than target. Proper monitoring plan was established in collaboration with production and subsurface
team. Mercury and other contaminant content will be closely monitored throughout well production to take
necessary action whenever its level spike above threshold.
Consideration on well design is a dynamic process where previous actual data served as strong signal for
a more comprehensive and cost effective well planning which brings value to the company. Integration with
various parties is the key success in getting the actual data and optimization options can be realized by fully
utilizing the actual offset data. With compilation of the actual data in-place engineering study can be more
representative and highly reliable that will eventually increase the probability of success of the project.
Acknowledgments
This work would not have made it this far without the generous support, collaboration, and dedication from
multiple stakeholders and service providers that have involved directly throughout completion planning
and operation. Thus, we would like to acknowledge engineers, offshore crew and management from
PETRONAS Carigali, Halliburton, Solar Alert, Petroclamp, Schlumberger, Baker Hughes, Geowell and
Velesto who have contributed in this work. Thank you.
References
1.
2.
3.
B. Chambers and M. Gonzalez.2019. Low Temperature Effect on Sulfide Stress Crack
Initiation in Low Alloy Steels. Paper Presented at the CORROSION 2019, March 24-28,
2019.NACE-2019-12856
IHS Markit. Reservoir Pressure and Horner Plots, https://www.ihsenergy.ca/support/
documentation_ca/accudst/theory/reservoir_pressure_and_horner_plots.htm (accessed 9th June
2021)
Jet Research Centre (JRC). TCP Firing Systems and Ancillary Equipment https://
www.jetresearch.com/content/dam/jrc/Documents/Books_Catalogs/04_TCP.pdf (accessed 14th
June 2021)
Downloaded from http://onepetro.org/SPEAPOG/proceedings-pdf/21APOG/2-21APOG/D021S010R005/2495939/spe-205634-ms.pdf by PetroVietnam University user on 03 January 2024
•
1
Frequency