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BD Field Development: First Kujung Horizontalnear HPHT - Critical Sour
Wells Offshore Indonesia
J. Lian, Y. Tian, Z. Yang, K. Yustendi, D. Rizkiani, S. Nurdin, D. R. Mcken, and M. O. Etuhoko, Husky CNOOC
Madura Limited; K. Jiang, CNOOC International Ltd.; A. P. Diemert, Husky Energy Inc.; M. Fadil, P. P. Utomo, A.
Mahry, and S. D. Yudento, SKKMigas
Copyright 2017, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition held in Jakarta, Indonesia, 17-19 October 2017.
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.
The Company had successfully drilled 4 challenging BD Development Wells (1 vertical and 3 horizontal).
BD Field reservoir is aKujung 1 limestone reef, considered near HPHT and critical sour with 8,100 psi
Bottom Hole Pressure (BHP), 300℉ Bottom Hole Temperature (BHT), 5.5% CO2 and 5,000 ppm H2S. This
paper highlights the design phase and well deliverability covering pressure window, casing design, material
selection, wellhead and Christmas tree, directional drilling planning, drilling fluid, cementing consideration,
well completion, annulus pressure management, and project challenges.
The data from two offset wells with surface location radius fewer than 2,000 ft from BD Platform were
used as reference for lessons learnt and design for the casing seat selection. Based on the Wellbore Stability
Study and the offset wells data, there exists a narrow mud weight window between pore pressure and fracture
pressure. The directional plan was developed to have sufficient well separation in the upper hole section and
enable fewer dog leg severity requirement to drill in the down hole section. Material selection for casing was
designed based on the expected life of the well and reservoir properties in accordance to the requirements
of NACE. Drill-in fluid system (Potassium Formate and Manganese Tetraoxide) with mud weight of 14.9
ppg was used to drill the limestone reservoir section providing minimal damage to the reservoir. Production
casing cement was tested and analyzed in the laboratory for 60days in the HPHT chamber simulating
reservoir properties. Open Hole Monobore Completion approach was selected to complete the well. In order
not to compromise well integrity, annulus pressure management technique was fully implemented during
drilling, completion, and well clean up phases.
The wells were successfully executed despite several challenges which required unique mitigations to
manage. During well clean ups, all wells were able to exceed the Absolute Open Flow (AOF) expectations.
BD Field is located offshore in the Madura Strait, East Java. The field was discovered in 1987 by the X1
wildcat well. The X1 well encountered oil and gas from Early Miocene carbonates/limestone (Kujung 1
Formation). A 3-D seismic survey was shot over the structure following the X1 well discovery. Two years
later in 1989, the X2 appraisal/delineation well was drilledto confirm the BD field discovery. The Kujung
1reservoir was considered near HPHT and critical sour with 8,100 psi BHP, 300℉ BHT, 5.5% CO2 and
5,000 ppm H2S – and containing mainly gas with condensate, overlying a relatively thin oil zone. Fig. 1
shows Stratigraphy of the Madura Strait Block.
Figure 1—Madura Strait block stratigraphy column (Modified from Widjonarko 1990)
During drilling the X1 and X2 vertical wells, several down hole problems(i.e., well control, stuck pipe,
loss circulation, and cementing problems) were encountered. During DST, high concentration of CO2 and
H2S gas were detected. The BD Field Plan of Development (POD) was very challenging in which there
were 3 horizontal wells to be drilled at the same time to ensure well productivity and integrity throughout
the well life. BD Field was expected to recover about 442 Bcf of gas and 18million barrels of condensate.
BD Field has a total of 4 producing wells - one vertical (Y1) and three horizontal (Y2, Y3, and Y4)and was
the first Kujung 1 horizontal near HPHT and critical sour wells offshore Indonesia.
BD Field was developed from an unmanned wellhead four-legged platform with 6 slots (10 ft × 10 ft)
and a jack up rig to drill the wells (water depth 182 ft). Platform location was placed at the centre of the
reef carbonate structure, in between the two offset wells X1 and X2. Y1 vertical well was drilled from
Slot number 4, Y2 horizontal well was drilled from Slot number 2 to North-West direction, Y3 horizontal
well was drilled from Slot number 3 to North-East direction, and Y4 horizontal well was drilled from Slot
number 6 to South-East direction (Fig. 2). Slot number 1 and 5 are intended for future infill development.
Figure 2—Platform slots configurationand well direction
Pressure Window, Setting Depth, and Casing Design
Offset wells X1 and X2 provided good information and were used as reference to study the pressure window
and casing setting depth. There was no shallow gas encountered when drilling well X1 and X2. Fig. 3
shows the offset wells casing setting depths. To have a better understanding, a Wellbore Stability Study
for BD Development Wells was conducted. In general, the top transition of the over-pressured zone was
observed starting at ± −5,150 ft SSTVD and the hard over-pressured zone starting at ± −6,400 ft SSTVD
with a narrow window between the pore pressure and the fracture pressure giving very challenging wellbore
stability issues (i.e., hole sloughing, loss circulation, pack off, well breathing) when drilling this zone. Top
of Kujung 1 in X2 well was at ± −10,600 ft SSTVD, with a pore pressure that was lower than the shale
section above it. There was a fracture pattern in the Kujung 1 core obtained from X1 and X2 wells which
was interpreted as coring-induced fractures and no fault was indicated.
Figure 3—Offset wells casing setting depth (not to scale)
BD well casing setting depth was designed with the following principles:
1. To avoid the upper casing shoe fracturing during drilling, tripping in/out, and well control operation.
2. To avoid two sets of pressure systems (over-pressured and depleted) co-existing in the same open hole.
3. To meetthe technical HPHT requirement with a safety factor design criteria >1.25 for burst, >1.125
for collapse, >1.8 for tension, and >1.25 for triaxial.
4. To avoid differential pressure sticking due to a pressure difference.
5. To use offset well casing setting depth data as reference.
6. To ensure a sufficient safety factor to set casing considering rig capacity.
Based on the above principles, the wells were designed with a 5 string design (30 in. conductor, 20 in.
casing, 13-3/8 in. casing, 9-5/8 in. casing, 7 in. liner) complete with 7 in. tie back and 4-1/2 in. pre-drilled
liner. The 30 in. casing conductor was driven to ±328 ft below mud line and was deeper than jacket piling
leg depth at ±319 ft below mud line. The 20 in. casing was set at ±3,250 ft TVD to enablethe next hole
section to be drilled to above the top of the transition zone. The 13-3/8 in. casing was set at ±5,800 ft TVD
for drilling the transition zone to the top of the hard-pressured zone. The 9-5/8 in. casing was set at ±8,200
ft TVD to have better shoe strength and minimizethe open hole length to drill the subsequent hole 8-1/2
in. section to the top of the Kujung Formation. The 7 in. liner was set at the top of the Kujung formation
at ±10,784 ft TVD to isolate the higher pressure system above the Kujung 1 Formation to ensure safety
5-7/8 in. production hole drilling. The 7 in. and 7-5/8 in. tie-back string was run and cemented after the
4-1/2 in. string lower and intermediate completion were installed. Fig. 4 shows the casing setting depth in
relation to the pressure window.
Figure 4—BD well casing setting depth in relation to pressure window
Special consideration was drawn to the intermediate casing design. The 9-5/8 in. casing was acting as an
intermediate casing when drilling 5-7/8 in. hole before the tie back operation of the 7 in. liner. However, its
material was designed with T-95 grade with premium(gas tight) connections and not the special Corrosion
Resistant Alloy (CRA) with considerations as follows:
1. Because casing wear will affect well integrity, 7 in. CRA tie backwas installed after drilling the 5-7/8
in. to minimize wear.
2. Further laboratory tests on the T-95 material sampleswere performed according to NACE to mitigate
risks during a well control situation while drilling the 5-7/8 in. and during the production phase.
3. No CO2 and H2S gaswas observed at the surface during drilling the production hole on the offset wells,
it was only observed during the drill stem test.
4. An over balanced operation and water based mud were selected to ensure hydrostatic pressure was
slightly greater than formation pressure and to minimize gas solubility.
5. A 7 in. tie-back was cemented full length up to the surface providing an additional barrier to the 9-5/8
in. casing during the production phase.
Material Selection and Connection Requirement
Material selection for production casing and tubing was critical to ensure well integrity in a critical sour and
HPHT environment. Based on the reservoir characteristic with partial pressure of H2S ±36.5 psi (> 0.05 psi)
and temperature 150℃, NACE MR0175/ISO 15156-1 standard requires SSC resistant steel to be selected.
The Company conducted a laboratory test in accordance with NACE TM0177-05 by a third party. Samples
of materials were tested for 30 days in a defined sour environment at an elevated temperature and pressure,
simulating the predicted BD down hole reservoir conditions. A number of samples were tested togetherto
choose which material offered by suppliers fit the purpose. The selected material was proven with results of
no localized corrosion, insignificant generalized corrosion rate (as indicated by weight changes were fewer
than 0.5 microns per year), and no cracking was detected on any of the specimens(Fig. 5).
Figure 5—C-Ring, Pitting, and Crevice samples before (left side) and after (right side) laboratory test
Production casing and tubing was designed withpremium (gas tight) connections in compliance to ISO
13679 – API RP 5C5 to meet Connection Application Level (CAL) IV. The requirement was purposed to
withstand the extreme load condition for HPHT environment. The requirement for connection efficiency
of 7 in. production casing and 4-1/2 in. production tubing was set to have 100% for tension, compression,
internal and external pressure.
Wellhead and Christmas tree
With the anticipated surface pressure of full gas-condensate column at +6,500 psi during production, the
Company used 10,000 psi wellhead and Christmas tree working pressure rating including more than 1.2
safety factor. Pre-production discussion with Project and Production Set Up departments was conducted
extensively to ensure the wellhead configuration fits for purpose (i.e., wellhead section height, valves
orientation, instrumentation valves configuration). The Company designed the wellhead and Christmas tree
with main requirements as follows:
1. Bore protectors to have fully sealing section to protect from damage, allow full gauge bits to be run,
self-retained and made of non-aggressive but wear resistant material.
2. Minimizing all changes in the bore inside diameter to minimize the effects of erosion.
3. Testing (including API SPEC 6A "Performance Verification Testing," Finite Element Analysis and
Factory Acceptance Testing).
4. True metal-to-metal / acid resistant seals in all production flow-wetted areas.
5. All production flow-wetted material shall be CRA with HH-NL material, PSL 3G, and X temperature
Conventional wellhead type was chosen to accommodate batch drilling operations. Wellhead sections
were installed offline during drilling on the adjacent well.
Directional Drilling Program
BD Field was developed from a platform. Optimizations were made with the following main considerations:
1. Optimizing the target location and in the same time minimizing impact to the well objectives while
ensuring sufficient well separation in upper hole section.
2. Reduce casing wear by minimizing turn/build in the (smooth) trajectory. Casing wear will affect well
3. This project was categorized HPHT and critical-sour, with smooth trajectory will help for success of
the campaign by reducing complexity.
4. Well collision consideration.
Soft formation was observed when drilling offset wells making directional operation in 26 in. hole
challenging. Close monitor on drilling Y1 vertical control well, especially observing softness of the
formation and bit deviation tendency, was used as reference. Separation in the 26 in. hole section was
executed successfully with kick off point at ±700 ft MD and returned back to near vertical at ±3,250 ftMD
using single run 1.5 degree AKO mud motor.
Ensuring verticality in the long vertical interval (17-1/2 in. and 12-1/4 in. hole sections) was critical since
those wells were drilled side by side to avoid collision issues and smooth trajectory to hit targets. Although
in the offset wells showed that deviation was fewer than 2 degrees, pre-caution was taken to maintain good
drilling parameters and proper BHA design to ensure the verticality of the hole still in the acceptable criteria.
Building angle from vertical to ±60-70 degree of inclination was conducted when drilling 8-1/2 in.
hole section penetrating Kujung Formation at ±10,600 ft SSTVD, followed by landing to ±90 degree of
inclination and drilled horizontally with 5-7/8 in. slim hole to total depth. The Company had successfully
drilled up to 1,100 ft of 5-7/8 in. horizontal section without any significant hole problem nor anyBHA left
in hole incident.Fig. 6 shows directional plan of BD wells.
Figure 6—BD wells directional plan (with offset wells)
Drilling Fluid
Water based mud system was used to drill four development wells in BD Field. Oil based mud was
not selected because of high risks of loss circulation hazards, well control issue of gas, H2S solubility,
and environment issues in Madura Strait location. Thick clay-stone formation with some sand stringers
dominates the upper hole section intervals until 8-1/2 in. hole section. The drilling fluids system was
basically polymer system treated with inhibition products and barite as primary weighting agent when
drilling 26 in., 17-1/2 in., 12-1/4 in., and 8-1/2 in. hole sections.Table 1 shows proposed mud weight and
properties to drill BD well.
Table 1—Proposed mud weight and properties for BD well
Challenges were encountered to drill reservoir section to minimizeformation damage as well
as building up to 14.9 ppg mud weight to drill the section. Several drill-in fluid systems were
evaluated considering formation pressure and temperature, reservoir compatibility, economics, contractual
complexity, environmental impact, and industry proven records as follows:
– Calcium bromide (CaBr2)
Clear brine that can reach desirable high density; however there were some issues with
crystallization temperature and reaction with zinc (like H2S scavenger) resulting harmful material
for environment.
– Phosphate-Based Brine
Clear brine that can reach desirable high density; however it was lacking of industry proven records
to be used in the Company critical project.
– Cesium Formate (CsCOOH)
Clear brine that can reach desirable high density; however contractual and financial issues
significantly limited its use. It was on rental basis and potentially highly expensive when dealing with
possible loss circulation issues.
Potassium Formate (KCOOH with Specific Gravity 1.57) and Manganese Tetraoxide (Mn3O4 with
Specific Gravity 4.8) system was selected. The system has been applied in the industry providing lessons
learnt and experiences (Al-Saeedi et al.2010). BD Field was the first use of KCOOH and Mn3O4 system in
Indonesia to drill Kujung Lime Stone Reservoir. Manganese Tetraoxide is characterized by its small particle
size diameter and spherical geometry. Because of its small size and shape, it can be cleaned up and easily
flowed back. Liquid potassium formate was used as base fluid to minimize solids content and Equivalent
Circulating Density (ECD). Laboratory test was performed to check the solubility of Manganese Tetraoxide
filter cake, with 15 % weight acetic acid and 50% volume chelating agent solution dissolved 100% filter
cake at 305° Fahrenheit and soaking time of 6 hours (Chendrika et al. 2017).
Long-term zonal isolation with produced fluid containing high content of CO2 and H2S is very challenging.
Carbonation of neat Portland cement systems can occur in CO2 environments (Moroni et al. 2008). Also,
in the HPHT and narrow pressure window well, it will be very difficult to place cement in the annulus and
avoid slurry contamination due to fracture pressure limitation. Volumetric shrinkage of the cement during
hydration can affect the porosity and permeability forming micro-annuli (Rubiandini et al. 2005).
According to NORSOK Standard D-010 Rev. 3, the purpose of cemented casing is to provide a
continuous, permanent, and impermeable hydraulic seal along hole in the casing annulus or between casing
strings, to prevent flow of formation fluids, resist pressures from above or below, and support casing or liner
strings structurally. In general, top of cement height shall bea minimum of 100 meters above a casing shoe
in which the cement column in consecutive operations is pressure tested / casing shoe is drilled out. For
BD, top of cement was designed to sea bed depth (182 ft below sea level) minimum, with considerations
as follows:
1. HPHT environment in which temperature cyclic loading is expected to occur.
2. Wellhead growth from un-cemented free pipe due to temperature effect.
The Company mitigated the risks by a laboratory test examination on the cement sample using an HPHT
corrosion test chamber (Fig. 7) simulating corrosive reservoir condition for 60 days. Further checks on
samples were evaluated, as follows:
1. Corrosion depth was measured using Scanning Electron Microscope (SEM) by comparing the micromorphology of the corrosion.
2. Cement mechanical properties (axial and triaxial) were evaluated after corrosion.
Figure 7—HPHT corrosion test chamber
Result shows that cement sample after test were acceptable; the cement strength was developed
under high temperature and high pressure, acceptable corrosion depth (maximum corrosion intrusion of
0.7millimeter, see Fig. 8), and achieving desirable cement elasticity property. Lessons learnt from cementing
offset well showed that spacer reacted with the shale formation portion resulting in hole problem. Hence,
spacer for all system was improved to be shale non-disperse for 10 minutes.
Figure 8—Cement samplesafter 60 days test showing corrosion intrusion depth (0.7 millimeter).
Well Completion
BD Field was developed with monobore completion concept due to its large flow area and big bore
advantages, facilitating excellent well intervention in future. The completion was divided into three (3)
main parts namely: Reservoir (Lower) Completion, Intermediate Completion, and Production (Upper)
Completion (Fig. 9).
1. Resevoir (Lower) Completion
Consist of pre-drilled liner, blank pipe, and a packer to hang the lower completion. The hole build
section and liner lap were covered with blank pipe to avoid early water breakthrough around heel
section and to reduce drawdown effect.
2. Intermediate Completion
Consist of the seal assembly, isolation disk to isolate the reservoir, and a packer to hang the
intermediate completion. The disk is 10,000 psi and V-0 (zero bubble) rated and allows performing
under balance operation above the disk. Coiled tubing, slick-line, and dropping the bar can be run to
break the disk. In order to prevent annulus pressure build up that can lead to collapse of completion
string in future, no seal was installed on the seal assembly. The seal assembly is only for mechanical
continuity in the completion string.
3. Production (Upper) Completion
Consist of the seal assembly, landing nipple, production packer, surface controlled sub-surface
safety valve (TR-SCSSV), and tubing hanger assemblies. Like intermediate completion, seal was
removed on the seal assembly. Down hole gauge to monitor down hole pressure and temperature was
installed in Y2 (west direction) and Y3 (east direction) wells.
Figure 9—Complete Well Schematic for Horizontal Well
Annulus Pressure Management
The annulus pressure build-up in BD wells was due to fluid thermal expansion during gas production. The
fluid thermal expansion may lead to high pressure trapped in the annuli that could compromise well integrity,
if not mitigated. This was seen also during well clean-up phase. Likely consequences are as follows:
Casing / tubing failure (i.e., collapse or burst),
Wellhead seal failures,
Loss of production,
Intervention inability or in a worst case,
Loss of engineered well barriers.
Following API RP 90, a work instruction to manage the annulus pressure build-up was developed and
communicated same to production department. It can be summarized as follows:
– Annulus bleed off operation shall be done slowly.
– Minimize long bleed off operations because it may lead to pressure cycling operation causing tensile
stress cracking in the cement. The recommended bleed off is 10-20% of the pressures in the annulus
during production.
– Set working pressure limits (upper and lower) for each annulus.
– Installation of pressure control valvesand alarm system tied-in to the annuli to manage the pressure
limits set for each annulus.
Well Control
The BOP and other well control equipment fitted for operations shall meet, or be greater than, all well control
requirements, regulations, and specifications for the reservoir pressure, temperature, and environment.
Several notes in regards to the well control equipment requirements are as follows:
– The metal material of well control equipment which contacts with H2S should have the property of
stress cracking resistance that complies with NACE MR0175 requirements.
– BOP temperature rating including internal rubber products, choke lines, kill lines, manifolds, and
valves are rated for 250° Fahrenheit.
– Flarebooms both on port side and starboard side including fuel for ignition system and water curtain
system shall be available.
– Double kill lines, choke lines, and MPD to be installed before drilling 8-1/2 in. and 5-7/8 in. hole
Managed Pressure Drilling (MPD) equipment was installed to establish a closed-loop drilling system;
to isolate gas breakout at surface (working area) which could contain H2S. The system was complete with
manifold system to enable application of surface back pressureduring drilling operations by varying the
choke opening. Surface back pressure also can be applied and maintained during tripping by use of rig
Project Highlights and Challenges
Preparation Phase
BD Field development project was unique in Indonesia because its complexity namely HPHT, narrow
pressure window, critical sour, offshore, and slim horizontal hole. Therefore, engagement of all parties (i.e.,
drilling contractors, vendors, logistics, and security) was vital in making this challenging project a success.
Several highlights of BD project preparation are as follows:
1. H2S management system was developed as follows:
▪ Emergency and contingency procedures.
▪ Clean shaven policy (i.e., no facial hair that could obstruct face seal when using breathing
To supply equipments and materials in case of emergency, additional shore base was provided.
Studying drill-in fluid feasibility to meet all requirements and cost effective.
Almost 2.5 years was spent to procure the CRA pipe including laboratory test until delivery.
Drilling and completion program development by Drill and Complete Well on Paper Exercises
involving all parties. Concerns were gathered and discussed and mitigations measures established.
6. Formal HPHT training and workshop by a recognized third party was held for all personnel involving
in the project including on-site training for drilling rig crews. The objectives were to:
▪ Develop an awareness of the challenges presented elevated temperatures and pressures in well
▪ Learn the key differences between "normal" condition wells and HPHT wells.
▪ Understand some of the indicators of thermal and pressure related problems.
▪ Understand the responses to mitigate HPHT challenges while drilling wells.
7. On-site training for shore baseand rig personnel was conducted by CRA tubular vendor. This is to
avoid metal-to-metal contact of the CRA tubular during storage, transportation and preparations, prior
to deployment in the wells.
8. Sourcing of a non-marking CRA tubular make-up system to minimize dies-mark on the CRA tubular
body to prevent corrosion.
9. Jack-up rig was audited by third party for safe drilling as per HPHT requirements.
10. Sour Service Grade drill pipes preparation; new pipe was required to mitigate risk of pipe failures
during drilling sour environments.
11. Sour service rated wireline cable was selected to withstand sour-environment.
12. Liner hanger and completion tools preparation ensuring pins shear tests value and connection makeup torque was within range.
13. Well clean up equipment preparation ensuring local regulations and maintenance records were in
Execution Phase
Batch operations proved to be time and cost efficient especially during upper completion and well cleanup operations. Y1 vertical well was used as control well and drilled to TD from 8-1/2 in. section onwards.
The lower and middle completions were run for reservoir isolation, cement plug set and 7 in. tie-back run
and cemented as temporary barriers, before moving on to following wells in batch drilling, completion and
clean up sequence. Several main advantages are listed below:
– Installation of wellhead sections and required testing of same was done offline after skidding the
cantilever to the next well slot.
– Reducing vessel requirements after fast top hole(s) completed.
– Re-using the same mud types and BHA, hence optimizing the efficiency for managing fluids,
rheology, and minimizing time for BHA handling.
– Cement evaluation logs for the majority were conducted offline.
– Well testing and CTU were mobilized and demobilized only once. Rigging up and rigging down for
successive wells were, for the most part, offline during rig skidding.
New sour-service grade drill pipe was used to drill 8-1/2 in. and 5-7/8 in. hole sections. In order to
minimize rig time, the sour-service grade pipes were made-up and laid down offline. Using new sour-service
grade drill pipe to drill 4 wells proved to be effective because there was no non-productive time (NPT)
related with pipe failures drilling sour environments.
Some challenges were encountered during wells execution and required mitigations:
1. Well control situationin Y2 well after cement in place 9-5/8 in. casing resulting annulus pressure. The
event was preceded by loss circulation and well breathing during cement displacement. Pumping-in
through wing valve was restricted due to tight injection rate.
2. ECD management to drill hole section from re-use of drilling mud with carried forward solids from
previous wells.
3. 8-1/2 in. hole section in which sand formation was encountered and resulting hole problems (loss
circulation, sloughing, and well breathing). Two wells were sidetracked due to loss circulation
and hole instability. Used reinforcement/strengthening technique with products based on graphite,
cellulosic, and poly-crystalline to solve hole problems.
4. In the control well Y1, before drilling into Kujung Formation, the directional BHA was pulled out of
hole and a simplified slick BHA re-run in hole to anticipate possible loss circulation.
5. Flow check in the HPHT zone was different than normal. Finger printing was performed by carefully
measuring the flow back rate and volume to differentiate between normal well relaxing (thermal
effect) or well control situation.
6. Low rate of penetration before penetrating top of Kujung formation in 8-1/2 in. hole due to high ECD
and surface torque during drilling. Surface rotary speed was adjusted to find best parameters to drill
the hole and reducing the TFA of bit nozzles to have more hydraulic power.
7. High hole drag running in the 7 in. liner which required pipe circulation and rotation. Surge and swab
calculation were used to help avoid loss circulation.
8. High torque during drilling 5-7/8 in. hole section, field calibration showing that friction factor for
open hole and cased hole was almost double than that modelled.
9. High hole drag running the lower completion through the 5-7/8 in. horizontal hole section.
10. From all four (4) wells running lower completion assembly, one run was stuck at heel section. Efforts
were made to release the pipe. However, since well control and potential release of H2S to surface
hazards when trying to release the pipe, trade off was made to set the lower completion assembly at
this point.
Lessons Learnt and Conclusions
BD Field by nature is HPHT and critical-sour and provided some very difficult drilling, casing/liner running,
drilling fluids management, cementing, and clean-up challenges, which were managed successfully without
a Lost Time Accident (LTA), oil spill or blow out. The lessons learnt from the project are as follows:
1. Lower FIT value than expected for 13-3/8 in. casing shoe which required remedial action to strengthen
the shoe strength.
2. Annulus pressure between 9-5/8 in. and 13-3/8 in. casing finding after cement in-place. Further
annulus pressure management was implemented for all wells to ensure well integrity and minimizing
bleed off to avoid pressure cycling that may compromise cement integrity behind 9-5/8 in. casing.
3. Shims between conductor pipe and platform jacket guide funnel below sea level was recommended
to be installed to minimize wellhead movement during rough sea condition.
4. Directional tool performance in high density and high solids content system requires special approach
to minimize failures. Witnessing the tool assembly in Contractor's Workshop is recommended to
ensure strict quality assurance. Focus was given to the part(s) that are susceptible to solids settling /
washes out by modifying tripping in procedures to ensure tool was operational on every pipe fill.
7 in. liner hanger working mechanism in the high density / high solids environment requires unique
modification, in which solids could potentially block the setting ports of the hanger. Liner hanger
Vendor modified the hook-up assembly to increase the "sump" available to accomodate solids not
plugging the hanger setting ports.
Further study on the cement evaluation tool to give 360-degree representations of the integrity of
cement job in high density mud. High density / solids environment affected sensor motor rotation
Managing solids content was a primary concern because the fluid volume was carried over from one
well to another on batch drilling mode. Fine particles increased significantly indicated by difficulties
to control ECD and increased values of torque and drag. Applied rehabilitated technique by relocating
some active mud volume into a separate mud tank, treating through centrifuge to remove fine particles,
diluting and reconditioning mud before pumping back into the active circulating system. The big bowl
centrifuge in solids removal mode was continuously run to remove the Low Gravity Solids (LGS) to
enhance stability of rheological properties. This was the most important part when introducing drilling
fluid into the reservoir, minimization of fine particles content and control of HPHT Fluid Loss below
10 cm3/30 minutes to reduce fluid invasion into reservoir.
High ECD challenges in slim hole drilling, 5-7/8 in. bit size can be replaced with 6 in. bit size.
Increasing bit size may lead to higher torque that can be addressed with special lubricant or motorized
Well known ester based lubricant has limited performance at high pH environment (pH ~11).
Alkalinity test is recommended during lab testing for compatibility.
Lower completion running challenges, special rigid centralizer under-gauge sizing can be applied to
reduce drag force while running in the open hole horizontal section.
Attention to detail for completion tools. Most assembly processes (make up assembly, pressure tests,
drifting tests) were conducted in the Vendor Workshop to ensure quality assurance for well integrity
and minimizing operation NPT.
Mechanical release of the hanger setting tool: In the intermediate completion, the packer was set
against the isolation disk to avoid operational complexities and problems. The consequence was to
release the setting tool mechanically. This requires left hand rotations of the string on the rotary table.
If not done properly, there is a high probability of backing off the string somewhere. The intermediate
completion setting tool was modified to have hydraulic release.
Breaking the isolation disk with CTU mill instead of impact hammer in which debris/solids on top of
isolation disk may hinder the impact hammer reaching it.
The planning phase was as challenging as operations phase to study, source materials, and experiences.
Debriefing of the recent operations and conducting lessons learnt discussions proved to be effective, to
improve the next operation. Detailedfield operational instructions were developed by the field company
representatives and were discussed with the office drilling team. During well clean ups and two mud cake
breaker stimulations, all wells delivered higher AOF than expected. Annulus pressure will be continuously
monitored throughout the life of the Project.
This project would not have been possible without support of many people, vendors, and contractors. The
authors would like to thank Satuan Kerja Khusus Minyak dan Gas (SKKMigas) that worked together with
us in making this challenging project a success. Thanks to Husky-CNOOC Madura Limited (HCML) and
Partners (Husky Energy and Samudra Energy) Management for the permission to publish this paper. Last
but not the least, appreciation for all team involved in the "war room" 24/7 accessible during drilling and
completion operation and all dedicated efforts.
Adjustable Kick Off
Absolute Open Flow
Billion cubic feet
Bottom Hole Assembly
Bottom Hole Pressure
Bottom Hole Temperature
Blow Out Preventer
Connection Application Level
Carbon Dioxide
Corrosion Resistant Alloys
Coiled Tubing Unit
Drill Stem Test
Equivalent Circulating Density
Hydrogen Sulfide
High Pressure High Temperature
Low Gravity Solids
Leak Off Test
Measured Depth
Managed Pressure Drilling
National Association of Corrosion Engineers
Non Productive Time
Potential of Hydrogen
Plan of Development
pound per gallon
part per million
pound per square inch
Product Specification Level
Rotary Steerable System
Scanning Electron Microscope
Sulfide Stress Cracking
Sub-Surface True Vertical Depth
Total Flow Area
True Vertical Depth
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API Recommended Practice 5C5, Third Edition, July 2003, ISO 13679:2002, Procedures for
Testing Casing and Tubing Connections.
API Recommended Practice 90, First Edition, August 2006, Annular Casing Pressure
Management for Offshore Wells.
API Specification 6A, Specification for Wellhead and Christmas Tree Equipment.
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IADC/SPE 112703 presented at the 2008 IADC/SPE Drilling Conference held in Orlando,
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NACE TM0177-2005, Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking
and Stress Corrosion Cracking in H2S Environments.
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