SPE 154371

Case History: Pilot Project with Coiled Tubing Drilling in Offshore South China Sea A.A. Abdul Rahman, SPE; , N.E. Hamzah, SPE; N. Ahmad Fauzi; N. Safiin, SPE; M.Z. Khalid, SPE; N. Syaifullah, SPE; PETRONAS Carigali Sdn. Bhd; J.R. Jenie, SPE; H.E. Hariry, SPE; Schlumberger

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition held in The Woodlands, Texas, USA, 27–28 March 2012. 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 The sustained and relatively high value of oil and natural gas has resulted in an unprecedented level of drilling activity and implementation of innovative methods to recover as much hydrocarbon as possible, and as quickly as possible. The resulting demand for conventional drilling rigs for programs has forced the rates high and the availability low, making use of the units difficult to justify for use in declining fields with less significant amounts of recoverable product. The by-passed reserves remaining accessible in these depleted fields exist in volumes worthy of pursuit, but must be done economically. In many fields, operators, either intentionally or unintentionally, bypass pay zones during initial development by focusing only on the best zones. Accessing bypassed thinly laminated formations can be economically attractive but poses several challenges, especially due to aged platforms and completion string in place, also offshore environment is adding its own challenges. Coiled Tubing Drilling (CTD) has yet to establish itself in an offshore environment. Numerous one-off projects have been tried, but commitment was never made to a number of wells to see through the learning curve and realize the potential of the application. Offshore South China Sea have a huge quantity of candidates on existing installations, installations that, due to water depths and sub sea conditions require large, expensive rigs to drill or re-enter wells. Technically the wells can be accessed with coiled tubing with drilling parameters seen regularly in other projects. The challenges for this pilot project will be equipment specification and set up, efficiently exiting the casing, and management of wellbore stability in open hole drilling and completion techniques. The main objective of this pilot project is to bring proven technology to offshore environment to access small bypassed reserves economically and provide an alternative to conventional drilling. The well candidates were selected with strict work scope to avoid going beyond the regular CTD application to ensure learning curve and lessons learned can be implemented throughout the project and achieve the objective. This paper will described the preparation, execution, achievement and lessons learned from this 4 wells pilot project in offshore South China Sea. Introduction PETRONAS Carigali Sdn Bhd operates a vast network of oil and gas producing fields, facilities and infrastructures in Offshore South China Sea, consist of more than 70 oil producing fields and more than 40 gas producing fields, specifically for Malaysia’s production network.

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The main producing fields, notably in offshore Peninsular Malaysia have been in production for an average of 15-20 years from over 100 platform structures. However, during recent years, the rate of production from these matured fields has decline. As the oil demand keeps increasing, the operators are continuously trying to find ways to boost up the performance of these fields. However, cost-effective development strategy of mature offshore fields has been a challenging objective in Malaysia. Conventional drilling and production techniques have not been able to produce the reserves at commercial rates because of the small and highly compartmentalized reserves. Drilling a new well to access small hydrocarbon pockets has proven uneconomical due to requiring offshore drilling rigs to drill or re-enter wells. Furthermore, the ageing platform and wells increase the risks and costs associated to safely drain the hydrocarbon. Hence, the initiative of utilizing an alternative drilling technology and techniques which involves minimum intervention on the existing wells and facilities were assessed and valued against the economic limit of the field. Re-entry drilling using existing wellbores was determined to be the best option to access those unexploited, compartmentalized pockets of hydrocarbon and coiled tubing (CT) drilling applications were evaluated. CTD, a pilot project of PETRONAS Carigali Sdn Bhd intends to maximize ultimate oil recovery by adding new drainage points in existing main producing reservoir by tapping directly to the undrained / bypassed reserves, with reduced time and costs to achieve targets. By benchmarking the performance from a similar project done in other parts of the world, this project was executed in a successful manner, and proven the feasibility of the technology to access the bypassed oil, offshore Malaysia. Overview of Coiled Tubing Drilling CTD was started in 1991 with a horizontal sidetrack re-entry drilled by Oryx Energy in the Austin Chalk of Texas. CTD can be described as drilling through exixting completion and allows the CT conduit to directly access the pay zones. CTD has proven track record over 600 directionally drilled wells, successfully completed in Alaska, USA. CTD experience is also being shared around the world and successfully being implemented in Canada, US Land, Russia, North Africa, Middle East and recently South East Asia. The application of CTD had an enormous growth over the last 10 years, moving from what was considered a niche market to mainstream drilling operation in several geographic locations. The re-entry work, the initial driver for the application, still exists and is thriving. The offshore application of CTD has been attempted for numerous years, with several projects done in South America, the North Sea and the Gulf of Mexico. While some of these projects met with qualified success, a sustained program has not been realized. This was primarily been due to one-well pilots with no chance for learning curves to materialize. Cyclic conventional rig rates have also been the contributing factor in the lack of progress in CTD application in an offshore environment. The drilling with CT has evolved from an experimental technique to a proven technology now used for nearly half of new wells on the North Slope of Alaska, USA. Alaskan Operators recognized the value in the lower cost/bbl for the CTD unit being able to sidetrack without a workover unit. Building on the Alaska success, other re-entry projects were started in the Middle East system moving within several United Arab Emirates fields, Saudi Arabia and eventually in South East Asia. All re-entry projects benefit from similar types of well design, utilizing exisiting surface facilities and the learning curves from continuous operations. Project Definition and Set Up This section will cover the candidate selection process, reservoir target selection, downhole and surface equipment selection, and operational risks based on the lessons learned and experiences from other similar ongoing CTD projects. Candidate selection The objective of the CTD re-entry campaign is to introduce the CTD as a cost effective solution to improve hydrocarbon recovery from area A. This process will evaluate and rank “candidate” wells based on CTD operating envelope from other ongoing projects that have similarities with these wells. This is to minimize the risk involved, both mechanically and financially to help justify the continuity of the application.

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In ensuring the level of success of this pilot project is positively high, tprojects in other part of the world. The criterias were

1. Remaining reserves limit > 0.5mmstb2. Field maturity and accessibility to areas of undrained3. Formation thickness > 10m 4. Reservoir target reachability < 1000m from kick off point to 5. Completion tubing size > 3-1/2” 6. Mechanical condition of existing tubing7. Platform condition and readiness

From 2 fields in Area A, field X and Y, there were these were the pool of candidates that went through further assessment. The candidates then divided into 3 types of completions which dictate

1. Thru tubing and set in casing exit. This will require thru tubing whipstock which the anchor will expand and set inside the casing. There is limitation of the anchor expansion, such as 3 ½” tubing cement kick off or set the whipstock inside pilot hole is the options.

2. Tubing exit with monobore whipstock. This category will require setting the whipstock inside the tubing and milling window thru tubing and casing (dual exit).

3. Dual completion, exit thru short string and casing.

Fig.

In ensuring the level of success of this pilot project is positively high, the selection criteria were developed based on similar projects in other part of the world. The criterias were as follows:

0.5mmstb Field maturity and accessibility to areas of undrained / bypassed reservoir

1000m from kick off point to total depth

Mechanical condition of existing tubing

Fig. 1: Candidate selection method

in Area A, field X and Y, there were initially a total of 17 wells which passed through the first screeningthrough further assessment.

The candidates then divided into 3 types of completions which dictate the complexity of the casing exit operationsThru tubing and set in casing exit. This will require thru tubing whipstock which the anchor will expand and set

There is limitation of the anchor expansion, such as 3 ½” tubing and 7” casing, for that scenario, cement kick off or set the whipstock inside pilot hole is the options. Tubing exit with monobore whipstock. This category will require setting the whipstock inside the tubing and milling

l exit). ual completion, exit thru short string and casing.

Fig. 2: Types of casing exits

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developed based on similar

passed through the first screening, and

the complexity of the casing exit operations (Fig. 2): Thru tubing and set in casing exit. This will require thru tubing whipstock which the anchor will expand and set

and 7” casing, for that scenario,

Tubing exit with monobore whipstock. This category will require setting the whipstock inside the tubing and milling

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Reservoir target selection The Company reservoir team had few target formations considered for the pool of candidates and with those formations, the vertical depth requirements allowed the estimation of where the well was to be exited for accessing the target zones. The positioning of gas lift valves, packers, centralizers, blast joint and casing set depths were all reviewed to determine if window placement could be done without overwhelming challenges such as triple casing exits (windows). The first consideration for the selection of a prospective casing exit point within the well is to view the well completion schematic and determine the least complicated means of exiting the casing. Multiple methods are possible to accommodate the design of a trajectory to target, but with the casing exit being a critical component within the program, selection of a method that minimizes the amount of effort, hardware, cost and risk is important. After initial designation of a casing exit point has been made, the second concern is the formation to be accessed upon milling of the window. By viewing gammaray logs from the original drilling of the well, the point chosen on the mechanical criterion is viewed, noting the gammaray results for presence of less desirable components such as unstable or problematic shale section. The design of the trajectory required consideration of several different items. As mentioned above, the exit point was determined with respect to the mechanical status of the existing completion, quality of cement behind casing, casing / production tubing collar locations and the formation to be entered behind casing. Having chosen a casing exit point, the next step in the process is to determine if the vertical depth target can be attained from the chosen point with a reasonable rate of build with the drilling assembly. Build up rates as high as 60°/100 feet are within the operating envelope of CTD operation; however, these require a thorough understanding of the behavior of the bottom hole assembly in the given formation, an understanding that comes only with experience. This candidate selection will keep the designed build up rate to less than 40°/100 feet, with most of the wells being in the 20s or 30s. Surface Equipment Selection Selection of CTD surface equipment is based on several considerations, as described below;

1. Zoned requirement Working on platform requires zoned equipment which escalates the complexity, availability and compatibility between parties.

2. Size and weight restriction Very important considerations were given to ensure load distribution to platform was not exceeded and HSE requirement is priority when planning equipment layout.

3. Platform readiness (structural study and modification) Aged platform may require platform strengthening and integrity check on the existing flow lines.

4. CT Pipe size selection and CT Injector capability Given the reservoir target depth and existing completion limitation, 2” CT with specific tapered design is selected based on all candidates to optimize Weight on Bit (WOB), overpull and hydraulic requirement. 5/16” monocable is required to control the CTD Bottom Hole Assembly (BHA) and data transmission. An injector head with maximum pulling capacity of 80,000 lbs is selected based on CT forces simulation.

5. Hydraulic horsepower requirement for mud pumps From hydraulic simulation, hydraulic horsepower is determined and CTD pump is selected based on the job characteristic, low flow rate and high pressure, and also continuous pumping.

6. CTD Sub structure or tower A CTD Sub Structure serves multiple purposes in a coiled tubing drilling operation, including support the coiled tubing injector head without crane attachment, to provide a platform for personnel to work (rig floor), act as a platform for safe working on pressure control and injector components, to provide three dimensional movement of the injector head for deployment and retrieval of the BHAs.

7. Drilling Fluids handling surface equipment Lower drilling fluids volume and lower pumping rate requirement, compared to conventional drilling activities, has allowed smaller footprint of surface equipment to be used for CTD. However, solid control in drilling mud is very crucial in maintaining hole cleaning and also as this will significantly affect the applicable WOB transferred to the end of CT BHA, those will limit the reach-ability. An integrated fit-for-purpose modular system especially developed for CTD application is proposed for this pilot project. In general, the surface equipment handling consists of shaker assembly, centrifuge, mud gas separator and compartmentalized active tanks (total 150bbls).

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CTD Bottom Holes Assembly (BHA) Selection All the selected wells have 3-1/2” completions, therefore 2 3/8” OD wired-CTD BHA is chosen for this pilot project. Casing exit BHA, whichever casing exit method used, will be done with CT milling assembly with diamond speed mill as the bit. The selection of diamond speed mill is based on success history where non aggressive surface of the bit is more forgiving when attempting to initiate the window. For build and lateral section of openhole drilling, 2.7 x 3” Bi-Center bit is chosen to maximize openhole size to allow running 2-3/8” completion liner afterwards. This drilling BHA includes Gamma ray, directional sensor, electric controlled orienter, and resistivity sub (as required basis). Openhole logging BHA is using CT logging head and Reservoir Saturation Tool (with 2 knuckle joints to assist in high dogleg section). The completion BHA includes hydraulic release, liner top, swellable packer, and 2-3/8” pre-drilled liner with flush joint connection. Drilling Mud Selection of drilling mud is based on below requirements and considerations:

• Weight Transfer to Bit – Given the limited available forces when drilling with CT, the lubricity of a drilling fluid is critical for a successful well. Minimizing solids in the fluids and maximizing the lubricity factor by addition of friction reduction agents has proven highly successful

• Hole Cleaning Capability - The inability to rotate the string results in a higher risk of solids bedding while drilling with CT, and the fluid properties must take this in to account. Additionally, because higher circulation pressures translate to less CT pipe life, the lower circulation pressures help in minimizing costs, and the fluids must balance solids suspension capability with friction pressures.

• Minimizing Formation Damage – A fluid used to drill the reservoir is either formulated with a minimum amount of solids or incorporates properly sized bridging agents to ensure minimal adverse effect on reservoir permeability.

• Borehole Stability – A suitable drilling fluid properties need to be formulated to provide enough overbalance to ensure borehole stability while drilling and tripping without compromising the differential sticking risks.

Based on the above requirements and also considerations of previous CTD history at other locations with similar formation and scope of works, a solids-free mud system was chosen for this pilot project. Offshore Structure / Platform Assessment One of the important parameters during candidates selection is the existing offshore structure to support all equipment required, especially the crane and deck limitation. These criterias were established to minimize the complexity of the equipment set up and simplify the job execution method. After detailed evaluation on several platforms, only two (2) platforms are considered meeting the objectives with some minor modification required. Both platform diagrams are shown on fig. 3 and 4.

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MWD

tool

Mud logger

Office

Mixer

Platform North

4.2m

Pipe

basket

0.5m

Mixer

Power

Pack

Reel

w/ CT

MWD cabin

4.2m

ChokeMud

Gas

Separ

ator

PanelPanel

Mud Lab

Cabin

Charge

Pump

Pumps Skid Shale Shakers and Tanks

MWD tool CT shop

Platform North

Pipe

basket

Control

Cabin

& HPU

Reel

Interf

ace

compressor

Escape Route

Escape Route

A-04

Reel

w/ CT

Mud

logging

Container

Platform West

Platform East

Pump

MixerMixer

Power

Pack

GensetG

enset

Alternative Escape Route

Genset

Back

Up

HPU

Fluid

tank

Fluid

tank

Fluid

tank

Choke

Mud

Gas

Separ

ator

Panel

Panel

Charge

Pump

Pumps Skid

Shale Shakers and Tanks

Pump

MWD cabin

CTD

Office

Mud Logging Mud Lab

BHA basket

Fig. 3 and 4: Platform A and B equipment layout Project team set up Finding the right people to do this pilot project was essential and not available within the South East Asia region as it is the first project of its kind in the area. Resources were mobilized from other CTD Projects around the world. As other projects had their resources requirement, a customized plan was put in place to bridge the knowledge gap by having a full dedicated team with specific experience with the technology and operations, supported with customized classroom and safety training done on specifc requirement basis. Prior to actual job execution, a mock up test for the equipment was done in the onshore base to simulate the actual set up offshore for crews familiarization and serves as a pre-mobilization integration between project team members. With all the design and operational aspects accounted for in the feasibility study, and supported by the successful pre-job evaluation and set up, the CTD pilot project was ready to commence drilling 4 wells in 2 fields in the South China Sea within 6 months from the initial mobilization from around the world. Execution Execution phase is divided into 2 programs, pre-CTD and the CTD program. The pre-CTD program is designed to prepare the CTD candidate wells to be ready for sidetrack. This pre-CTD was done while mobilizing the CTD package in to the country. The well preparations utilize the conventional CTU, slickline and eline equipment to Plug and Abandon (P&A) the well and set the whipstock. The scope of work to prepare the candidate wells mainly are:

1. Coiled Tubing Unit: clean out, pumping cement, milling cement, milling nipple profile 2. Slickline equipment: Tubing integrity, caliper run, drift run, impression block 3. Eline equipment: orient and set whipstock, set bridge plug or TT bridge plug, set cement retainer, 1-11/16” Cement

Bond Log (CBL)

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The CTD program was planned with 4 main steps with each step has key objective: window milling, drill build and tangent section, openhole logging, and completion and well reinstatement.

1. Window milling The objective is to provide access to the formation. The plan was to make two runs, the first one was to create window in tubing and or casing and the second one is to dress or ream the window.

2. Drill build and tangent section This drilling openhole was planned with 2 drilling BHA: 1st BHA is to drill build section to landing point with bent housing. Second BHA is for tangent section, which is to drill to planned final depth with reduced angle bent housing.

3. Openhole logging. To determine the Gas Oil Contact (GOC) and swellable packer placement, an additional RST tool run is needed and also 1 additional clean out run with drilling BHA to prepare the openhole for liner running.

4. Completion and well reinstatement The plan was to make up pre drilled liner with pre-determined depth for swellable packers for isolation, run it to total depth and release the liner in the openhole. Drilling mud will be displaced with diesel and slick line will open the gas lift mandrels prior handing over to production.

Well No. 1 The first well selected was based on the complexity casing exit method and drilling trajectory to ensure high degree of success and confidence. This well is also located in the larger platform of the two to reduce the potential set up issues due to first mobilization. With the existing well configuration is 3 ½” tubing and the target Kick Off Point (KOP) is inside 4 ½” casing, this require thru tubing whipstock to set inside 4 ½” casing. The plan is to set cement plug on the existing perforation in 4 ½” casing and leave Top Of Cement (TOC) below KOP (Fig. 5). Pre CTD program: Using a conventional CTU, the No-go nipple was milled from 2.69” to 2.8” ID to allow window milling assembly to pass through. Eline run with thru tubing CBL was then done 20m above and below planned KOP to evaluate the cement quality behind the 4 1/2” casing. Then, the Plug and Abandon of the perforation inside 4 ½” casing commenced, where cement was spot squeezed as necessary. With the top of cement (TOC) was slightly higher than planned, milling cement was performed with underreamer. Using E-line, the thru tubing whipstock with oriented setting tool was set to 10deg high side. Window milling: The window in 4 ½” casing (single exit) was planned to be milled with straight motor and speed mill, however had trouble to start milling due to off-centered whipstock setting position. Decisions made to set second thru tubing whipstock with CTD BHA, and confirmed the correct placement with slickline Lead Impression Block (LIB). Milled the 4 ½” casing with straight motor and speed mill without any issue using seawater. Performed Leak Off Test (LOT) and swap to water based mud system prior Pulling Out Of the Hole (POOH). Drill build and tangent section: The first build drilling BHA was planned with 0.8 bent motor and bicenter bit 2.7” x 3” PDC. Upon drilling 20m openhole, experienced stuck pipe which prognosed due to differential sticking. Displace the annulus with lighter density fluid, diesel and got free. Continued drilling with lower Equivalent Circulating Density (ECD) and experienced another stuck pipe, freed with same method to get unstuck. Decision was made to swap to Synthetic Based Mud (SBM) to achieve lower ECD. Continued drilling, however experienced 2 stuck pipe incidents, which led to hole packed off. Total openhole drilled was 167m, with total 4 BHA changeout due to electronic malfunction. After several attempts made to to free the pipe, decision was made to chemical cut CT string. Cut the CT string at surface, pull the e-line cable from inside CT string, ran 6 tubing punches to re-gain circulation, swapped fluid to water based, performed chemical cut and rig down.

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Fig.

Well No. 2 The second well was located on smaller platformand layout. The existing well configuration is 3 ½” tubing packer and in between upper and below production packers. needs to mill the 3 ½” tubing and 7” casing (dual exit window). The plan is Plug and Abandon (P&A) both perforation with cement to provide isolation, then set monobore whipstock inside 3 ½” tubing above upper produmilling (Fig. 6). Pre CTD program: First cement plug thru CT was to sealed the lowest perforation inside 7” casing, pressure tested. For the lower cement packer job, a bridge plug was set with eline inside tubing right above the lower production packer and performed tubing punch to gain circulation to tubingthe tubing punch and CT was run in hole with stinger to perform cement job. Upon successful the first cement packer job and tested, the same sequence was perform for the upper production packer. This cement packer was evaluated using slimhole Cement Bond Log (CBL) for isolation and TOC to ensure compliance with setting the whipstock using eline orienting tool. Window milling: First run was with straight motor to eliminate the bottom lip. The window milling went slight deeper without signs of exiting the casing ( tracking down the casing tubing annulus) subsequent run and successfully exit the tubing and casing. Drill build and tangent section: The build section was planned for drilling build section, it was noticed descrepancies on the toolface and update the well trajectory. Upon assessment the revtrajectory, it was determined that the bottom shale will be penetrated if continue, thplug in the openhole and re-do the build section. Several attempts were made to place cement plug inside the openhole due to the presence of short rat hole between tubing and casing from previous window milling acinside openhole, drilling build section commenced and successfully ldrilling the openhole with lateral drilling BHA including resistivity sub with total openhole ddifferential stuck pipe events encountered, which were successfully released with pumping lower density fluid. Openhole logging: An openhole Reservoir Saturated Tool (RST) was run with eline CT Contact (GOC) depth for swellable packer placement in the completionthe clean out run after logging to replace the loss of annular friction during making up the completion string. Completion and well reinstatement: Final completion string configuration with 2 swellable packers to isolate the gas zone with blank tubing, and flush joint pre-drilled liner to cover oil zone, was run in hole. inside openhole, the CT was stopped and unable to made to reduce hydrostatic including pumping and displace the well with diesel and re-instate the well.

Fig. 5, 6 and 7: Well 1, 2, and 3 diagrams

he second well was located on smaller platform in another field Y with different set up due to the limitation of and layout. The existing well configuration is 3 ½” tubing inside 7” casing, with the perforation are below lower production packer and in between upper and below production packers. The planned KOP is above the upper productineeds to mill the 3 ½” tubing and 7” casing (dual exit window). The plan is Plug and Abandon (P&A) both perforation with cement to provide isolation, then set monobore whipstock inside 3 ½” tubing above upper production packer for window

First cement plug thru CT was to sealed the lowest perforation inside 7” casing, . For the lower cement packer job, a bridge plug was set with eline inside tubing right above the lower

roduction packer and performed tubing punch to gain circulation to tubing-casing annulus. A cement retainer was set above the tubing punch and CT was run in hole with stinger to perform cement job. Upon successful the first cement packer job and

the same sequence was perform for the upper production packer. This cement packer was evaluated using slimhole Cement Bond Log (CBL) for isolation and TOC to ensure compliance with companys’ abandonment policy. Final step was

eline orienting tool.

First run was with straight motor to eliminate the bottom lip. The window milling went slight deeper ( tracking down the casing tubing annulus) and it was corrected with 2.5deg bent motor on

subsequent run and successfully exit the tubing and casing.

The build section was planned for 40 deg/100ft using 2.5 deg/100ft bent housing.drilling build section, it was noticed descrepancies on the toolface and update the well trajectory. Upon assessment the revtrajectory, it was determined that the bottom shale will be penetrated if continue, therefore decision was made to place cement

do the build section. Several attempts were made to place cement plug inside the openhole due to the presence of short rat hole between tubing and casing from previous window milling activity. Upon cement plug placement inside openhole, drilling build section commenced and successfully landed the build section with 60 deg/100ft DLS

BHA including resistivity sub with total openhole drilled was differential stuck pipe events encountered, which were successfully released with pumping lower density fluid.

An openhole Reservoir Saturated Tool (RST) was run with eline CT in the openhole Contact (GOC) depth for swellable packer placement in the completion string. A heavier mud pill was placed inside tubing

to replace the loss of annular friction during making up the completion string.

inal completion string configuration with 2 swellable packers to isolate the gas zone drilled liner to cover oil zone, was run in hole. After 282m of completion string went

and unable to run in further, suspected due to differential sticking. Several attempts were pumping nitrogen without success. Decision was made to release the liner, set in place

instate the well.

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limitation of crane capacity below lower production

The planned KOP is above the upper production packer, which needs to mill the 3 ½” tubing and 7” casing (dual exit window). The plan is Plug and Abandon (P&A) both perforation with

ction packer for window

First cement plug thru CT was to sealed the lowest perforation inside 7” casing, confirmed TOC and . For the lower cement packer job, a bridge plug was set with eline inside tubing right above the lower

casing annulus. A cement retainer was set above the tubing punch and CT was run in hole with stinger to perform cement job. Upon successful the first cement packer job and

the same sequence was perform for the upper production packer. This cement packer was evaluated using slimhole abandonment policy. Final step was

First run was with straight motor to eliminate the bottom lip. The window milling went slight deeper and it was corrected with 2.5deg bent motor on

deg/100ft bent housing. During drilling build section, it was noticed descrepancies on the toolface and update the well trajectory. Upon assessment the revised

erefore decision was made to place cement do the build section. Several attempts were made to place cement plug inside the openhole due to

tivity. Upon cement plug placement deg/100ft DLS. Continue

rilled was 927m long. Three differential stuck pipe events encountered, which were successfully released with pumping lower density fluid.

in the openhole to obtain the Gas Oil A heavier mud pill was placed inside tubing in

to replace the loss of annular friction during making up the completion string.

inal completion string configuration with 2 swellable packers to isolate the gas zone of completion string went

due to differential sticking. Several attempts were n was made to release the liner, set in place

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Well No. 3 The 3rd well was located in the opposite side of the the 2nd well on the same platform. There is only 1 production packer and the planned KOP is above the packer, which requires milling of the 3 ½” tubing and 7” casing (dual exit window). It is required to place cement plug across existing perforation and cement packer above the production packer prior setting the monobore whipstock inside tubing (Fig. 7). Pre CTD program: A cement plug was set with CTU to seal off the perforation and pressure tested. A bridge plug inside the tubing was set using E-line just above the production packer, then punched tubing, followed by setting cement retainer above it. Continued cement job using CTU, thru cement retainer and circulate to tubing-casing annulus. On slimhole CBL data, the cement interpretation was not solid all the way and there was indication of small leak during pressure test. Decision was made to re-do the cement packer job with CTD unit due time constraint. Window milling: Prior setting the whipstock, remedial cement job need to be done following the pre CTD program. By using E-line performed tubing punch in the lowest poor bonding area and CTD package placed the balanced cement plug into the tubing-casing annulus to ensure uniformity of cement plug. The cement inside tubing was milled to 20m below planned KOP and eline ran the slimhole CBL to evaluate the cement bonding, which showed good result and the TOC was more than adequate to satisfy the isolation in the annulus. The whipstock was set using Eline CT and orienting BHA, facing 10deg right. The position of the whipstock was confirmed with slickline LIB run. Window milling was done with 2 runs, first with straight motor to mill the tubing and second with 2 deg bent motor to mill the casing and rat hole. Drill build and tangent section: The build section was planned for 40 deg/100ft DLS using 2.6deg bent motor. Drilling build section was slight ahead of the plan, obtained 55 deg/100ft DLS with the last several meters were projected to landing point. Drilling the lateral section commenced for few meters and realized the discrepancy on the projection angle at landing point was not as expected, decision was made to change with build BHA with 2.6deg bent motor. Continue build angle for few meters and swap back with lateral BHA to continue drilling to TD. Two differential stuck pipe events were encountered, which were successfully released with pumping lower density fluid. Decision was made to call TD early due to the changes in lithology expected, adding to difficulty to initiate drilling beyond 3,100m MD. Furthermore, few differential stuck pipe were encountered in the last 60m of open hole drilled. Total openhole drilled is 640m from window Openhole logging: The plan was to run RST tool in the openhole to obtain the GOC for swellable packer placement. The first logging run had intermitten data transfer and the logging was completed in the 2nd run. After that, CT performed clean out run with drilling assembly prior making up the completion string. While POOH, lay drill beads inside openhole to reduce friction during completion run. Completion and well reinstatement: Final completion string configuration with 2 swellable packers to isolate the gas zone with blank tubing, and flush joint pre-drilled liner to cover oil zone, was run in hole. The completion run was smooth, went thru build section and lateral, but started to experienced high friction ~190m from TD. Continue ran in hole and finally stopped 134m from TD. The completion was not stuck differentially, but could not gain any footage from the initial hold up depth. Decision was made to release the liner and displace the tubing with diesel, re-instate well, rig down and move to next well. Well No. 4 Well no. 4 was anticipated to be the most challenging and was left to be drilled last from all due to existing completion schematic which dictates the casing exit scenario. Iit has 3 ½” tubing and the KOP is inside 7” casing. The plan is to mill no-go nipple, placed cement plug inside 7” casing all the way to approximately 20m inside production tubing, drill pilot hole and set monobore whipstock inside pilot hole then mill the 7” casing. Pre CTD program: A milling run was performed with conventional CTU to mill the no-go nipple to 2.8” ID to allow milling assembly to go thru. Drift run with slickline to check the ID of the no-go nipple, followed by slimhole CBL to confirm the cement isolation behind casing, especially in the +/-20m of KOP. Then pumped cement to plug existing perforation and also provide support for the whipstock.Conventional CTU milled the cement inside tubing until 34m below end of tubing to ensure the cement placement and isolation. Window milling: CTD unit milled the remaining pilot hole with straight motor and 2.8” speed mill, then the last 10m with 1deg bent motor to high side, to ensure the whipstock is touching the 7” casing. Slickline ran multi finger caliper to confirm the ID of the pilot hole inside casing to ensure that the hole size is within the specification of the whipstock. The whipstock

10 SPE 154371

was set with CT and oriented to 20deg right as planned and confirmed with slickline LIB that the top of whipstock was in correct position. Window milling was done in 1 run with straight motor and speed + string mill without any problem. Before pulling out of hole, performed FIT and swap to SBM for openhole drilling. Drill build and tangent section: Build section was planned with 35 deg/100ft DLS and 2.1deg bent motor. Drill the build section and landed close to the plan (achieved 34 deg/100ft DLS) and followed by lateral drilling BHA with 0.7deg bent motor all the way to TD. Total openhole length was 603m. No stuck pipe incident experienced during openhole drilling. Openhole logging: The openhole RST run was completed in 1 run and followed by clean out run including laying drill beads in the openhole with drilling BHA prior running completion string. Completion and well reinstatement: Make up completion string assembly with 2 swellable packers and flush joint pre-drilled liners with total length of 580.5m (fig. 8). Displaced the tubing with diesel prior POOH, re-instate well and demobilization of the CTD package.

Fig. 8: Well 4 final completion

Project Highlights and Lessons Learned Summary Pre CTD program:

• Performing pre-CTD with conventional CTU, slick line and eline units are considered successful, however, it needs to be done earlier to accommodate any changes encountered during the well preparation, allowing any remedial job to be done sooner than CTD package arrival

Window milling: • Establishment of suitable and practicle techniques for single casing exit, dual casing exit, and also setting whipstock

inside cement pilot hole which were successfully done in single attempt. • Proven the suitability of using either an E-line or CT Eline to set and orient whipstock an required for drilling

Drill build and tangent section: • The practice of drilling relatively faster (up to 60m/hour) with frequent wiper trips proven to minimize differential

stuck situation in the wells

SPE 154371 11

• Hole cleaning schedules were monitored closely and improved whenever necessary according to hole condition • With CTD, Real Time constant bottomhole pressure (ECD) technique can be applied whenever needed by using

choke • Uniform annular profile helps avoid pockets where solids can settle and jeorpardize the hole cleaning ability • Maintaining borehole stability is critical in CTD and needs to be plan accordingly, balancing the off risk of mud

lossess in depleted formation versus borehole instability Openhole logging:

• Openhole logging equipment (1-11/16” in size) successfully being ran thru up to 60 deg/100ft DLS without failures • Clean out run with drilling BHA prior making up completion string is highly recommended to ensure high success

rate of running the 2-3/8” pre-drilled liner to bottom Completion and well reinstatement:

• In the effort to increase the chances of getting the liner down to bottom, drill beads were used, however, the impact was not significantly noticed in the open hole friction reduction, however a recommendation to use higher concentration beads and placed it in the tubing is worth to be experimented in similar operation

Conclusions

• CTD is proven to be feasible as an alternative re-development option to access bypassed reserves in mature offshore oilfields economically

• Early detailed engineering planning, including candidate selection, basis of design, equipment selection and offshore structure / platform assessment – is very important and proves as a very critical stage to ensure high rate of success of the project.

• The flexibility to make changes to the drilling program in response to operational challenges is a must. As a result the learning curve developed will be very steep and re-currence of problem can be eliminated.

• This pilot project captures a significant improvements in the learning curves from one well to another, covering the novel drilling practices to the successful implementation of rare operations such as the monobore whipstock placed inside cement pilot hole and cementing through CT Eline job.

• Having good team integration offshore and at the office, is the key success factor for this first pilot project in Malaysia.

Acknowledgements The authors would like to thank PETRONAS, PETRONAS Carigali Sdn Bhd and Schlumberger management for their support and approval to publish the paper. References

1. Goodrich, G.T., Smith, B.E., Larson, E.B., “Coiled Tubing Drilling Practices at Prudhoe Bay”; IADC/SPE 35128 2. Rixse, M., Johnson, M.O., “High Performance Coil Tubing Drilling in Shallow North Slope Heavy Oil”; IADC/SPE

74553 3. DeWitt, Ron, “Technical Feasibility Assessment for Coiled Tubing Drilling” 4. D.E. Venhaus, SPE, and C.G. Blount, SPE, ConocoPhillips Alaska Inc.; K.E. Dowell, SPE, Schlumberger, L.L.

Gantt, SPE, ConocoPhillips Alaska Inc.; J.G. Sarber, SPE, and A.J. Worthington, SPE, BP Exploration (Alaska) Inc.; and M.G. Rixse, SPE, Baker Hughes Inteq., “Overview of the Kuparuk CTD Program and Recent Record-Setting Operations”; SPE 100210

Conversion Factors bbl x 1.589873 E-01 =m3 ft x 3.048 E-01 =m OF (oF-32)/1.8 =OC in. x 2.54 E+00 =cm lbm x 4.535924 E-01 =kg psi x 6.894757 E+00 =kPa