OTC-24752-MS

Coiled Tubing Deployed Electrical Submersible Pump (CT-ESP) Application at Offshore Operation Hasmizah Bakar, Ivan Chee Xianlung, M Irsyaduddin M Rozali, M Zulhairi M Nadzri, Kamal Mohamad Ayad, Juhaidi Jaafar PETRONAS Carigali Sdn Bhd

Copyright 2014, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference Asia held in Kuala Lumpur, Malaysia, 25–28 March 2014. This paper was selected for presentation by an OTC 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 Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference 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 OTC copyright.

ABSTRACT T offshore field is located in north-west of Kota Kinabalu, Sabah, Malaysia and has been in operation for 40 years. The major challenges faced by this field are depleted reservoir pressure, gas-lift compressor frequent interruptions and shortage of gas-lift supply. Various alternative artificial lift technologies have been evaluated. Electrical Submersible Pump (ESP) was identified to be the most operationally fitting technology to increase production, prolong field life and increase the ultimate recovery. Historically, T field had attempted with downhole hydraulic jet pumps to lift the oil. ESP deployment via coiled tubing (CT-ESP) was deemed the most economical due to rigless intervention and significantly shorter trip times into the well as compared to the time taken to make up conventional jointed tubing. Within 2 years, this technology has successfully contributed over MYR 18 million cost saving from 3 rigless workover and zero Lost Time Injury (LTI). This paper will share the journey and lessons learnt of the project starting from technology assessment, planning to execution phase. The experience gained during this project will be a valuable input in replicating the ESP deployment method for other wells in this platform and for other offshore prospects in term of safety, performance, reliability and cost saving. INTRODUCTION After producing for almost 40 years, T field is not only facing issues related to aging facilities such as structural and well integrity but also experiencing low reservoir pressure which is now at about 1000 -1500 psi or about one-third to half of the initial. The oil producers couldn’t flow naturally and needed artificial lift to assist their production to surface. About 80% of the production comes from gas lifted wells. The production couldn’t be improved further as the gas lift compression pressure is only limited to 1000 psi with 2.0 MMscfd of gas lift volume. T field also had once attempted downhole hydraulic jet pump to lift quarter of the platform’s oil but the results were not encouraging. ESP was introduced and has been identified as the ideal artificial lift to boost the production and prolong the field life here. Based on the key success drivers of workover rig cost & availability, operating cost (OPEX), mobilization time and actual installation time, the rigless deployment method was proposed. Alternative method of external cable CT-ESP was sought out which only required CT injector rig to install and pull out the ESP. The production through CT will be same as jointed pipe and no wellhead modification required.

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PROJECT PLANNING Selection of Artificial Lift Method Over the past 34 years of field production, Gas Lift has been the company standard mode of artificial lift. Recent shortage of gas lift supply and frequent compressor failures has challenged the traditional production philosophy and a new mode of accelerating the reserves is needed. After considering the matured field condition in addition to the benefit of production assurance and acceleration, ESP was chosen as the alternative artificial lift method. Selection of ESP Deployment Method Extensive study was conducted to decide on the most feasible ESP deployment for offshore environment. Two main methods were compared: jointed tubing and coiled tubing. Table 1 shows the duration and economic comparison between jointed tubing, which requires a Hydraulic Workover Unit (HWU), and coiled tubing, which requires Coiled Tubing Unit (CTU). Critical items such as Rig Mobilizing and Demobilizing Cost, Rig Crew availability, and the number of days required to POOH/RIH the completion shifted the deployment preference towards CTU. Well Selection and Platform Preparation In order to select the right well candidate, the team came out with six (6) elements: Reservoir, Well Geometry, Platform, Utilities/Logistic, Contracting Strategy and Execution. Reserve, reservoir characteristic, productivity index and solid production are among the crucial items under Reservoir. ESP system consists of surface equipment which are Variable Speed Drive (VSD), transformer, and generator. Preparations for deck space, zone classification, lifting gear and structures integrity were carried out in parallel. Figure 1 shows the detailed workflow chart for CT-ESP candidate selection. JOB EXECUTION Well A was selected as candidate for CT-ESP, primarily to realize the 0.6 MMstb locked in potential after being idle for 22 years. The execution of Well A CT-ESP was not a walk in the park. From project inception in 2008 to First Oil it took more than 3 years. Issues on reservoir, subsurface, completions, contract and logistics posed as the major challenges for the team to tackle. This section will describe the endless efforts undergone by the team to make this project a success, incorporating operational challenges and most importantly the lessons learnt for future technology replication. 2008 – Well A was initially a single string jointed tubing completion with only single perforation (Figure 2). Factors such as gas lift compressor frequent downtime and shortage of gas lift supply coupled with various well integrity issues (failed to change gas-lift valve to lowest mandrel, sand held up in well) rendered this well unable to produce as expected and was the main driver for Well A to be workover and recompleted with CT-ESP. While waiting for the Coiled Tubing Unit (CTU) to arrive, the well has been successfully workover using HWU (Figure 3). Old completion was POOH, new zone was perforated, installed sand production mitigated via IGP and well properly killed to maintain pressure integrity. Fluid loss valve was set to prevent kill fluid from flowing into the perforation. During this workover job, around 40,000 bbl of LCM was dumped into the well for well control. 2009/2010 – Well A was completed as per Figure 1. For the first few months, well was not producing as there was no reservoir feeding. For the next 9 months, extensive troubleshooting was conducted to identify the reason for this well not to produce as per Table 2. 2011 – The reason for non-production was identified as plugged Auto Flow Valve (AFV). In 2011, CT-ESP completion was POOH and rerun exactly the same completion excluding the AFV (Figure 4). Production started at 200 bopd but rapidly declined after few months’ production. It was suspected due to reservoir damage from previous workover operations (40,000 bbl LCM) and scale build-up from previous experience of plugged check valve and AFV & ESP retrieved covered with scale. Non-acidic chelating agent was bullheaded through the annulus to treat scale problem downhole. Production rate maintained was 400 - 480 bopd till to-date.

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LESSONS LEARNT

¢ During 2008 workover, actual reservoir pressure was much lower than expected. The kill fluid density was

concocted as per initial pressure estimation. This caused extreme overbalance in well control fluid, resulting in

40,000 bbl LCM pumped into formation. Lesson learnt: Conduct timely SGS so that proper well control fluid

weight will be used during workover operation to minimize formation damage in a depleted reservoir.

¢ During 2009 well intervention, filtered sea water was used to kill the well. This fluid stayed in the well for more

than 1 year, which resulted in ideal breeding ground for Sulphate Reducing Bacteria (SRB) which produces H2S.

Lesson learnt: To properly treat and inhibit the seawater used for well killing.

¢ In 2010, the problem causing Well A to not produce was identified. Unavailability of backup ESP assembly delayed

project for more than 3 months. Lesson learnt: To always check the availability of back-up equipment. Need to

impose that back-up equipment be checked and inspected regularly as per contract.

¢ This CT-ESP project was new to us, lack of proper planning & operational experience. Lesson learnt: Single-point

responsibility contract to a reliable company whereby contractor will provide everything inclusive of surface

and subsurface ESP equipment. Must also impose technology & information transfer during job execution.

¢ Frequent communication between all parties to ensure smooth operation. (For this case, missing critical

equipment, project execution delay)

¢ Proper planning & understanding of requirement and limitation of platform surface facilities e.g. crane

lifting capacity, power supply.

VALUE CREATION

¢ OPEX: Negotiation with the contractor managed to reduce CT-ESP daily rental by 5% for every 180 operational days.

¢ Production Increase: The well was idle for 22 years (last production in 1989 = 150 bopd) which is value equivalent to RM 200 million production deferment. CT-ESP application resulted in 300 bopd gain and a net revenue of RM 18 million.

¢ Time and cost saving: Since CT-ESP installation is rigless operation, it only required two (2) days for rig up and rig down CTU compared to HWU which needs 6 days.

¢ New Innovation: This is the first CT-ESP application by PETRONAS operation. This effort has created the in-house technical capability in the CT-ESP technique.

¢ Business Process Improvement: The team managed to go with Single Point Responsibility contract strategy, which has minimized dealing with multiple contractors.

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Table 1 – Comparison between CTU and HWU for POOH and reinstallation of ESP system

Item Number Description CTU

(RM million)

Rig (HWU)

(RM million)

1 Rig Mobilizing and Demobilizing cost 1.784 3.162

2 Work barge mobilization cost 1.116 1.116

3 Daily rig cost per day NA 0.054

4 Daily barge cost 0.285 0.285

5 Dedicated supply vessels daily rate

(3 vessels)

0.954 0.954

6 Number of days required (to POH/run completion) conventional completion without ESP assembly

2 5

7 Number of days required for rig up 1 3

8 Number of days required for rig down 1 3

9 Rig crew 10 23

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Table 2: Detailed Troubleshooting

Date Activity Results

15th

July 2010

Dumped 250 bbls inhibited sea water into annulus & 40 bbls through CT

There is communication between annulus and CT which indicated that the auto flow valve (AFV) is stuck in the down position and open to annulus. Started the ESP for 2 hours with no sufficient build up pressure.

20th

July 2010

Dumped inhibited water through annulus and started the pump when Pi stabilized @1500 Psi and kept unit running for 4 hours

No fluid at the surface and no sufficient pressure build up. SD the unit manually.

28th

July 2010

Dumped inhibited water through annulus and started the pump when Pi stabilized @1500 Psi and kept unit running for 4 hours

No fluid at the surface and continue to increase frequency 1 Hz every 10 minutes until 48 Hz with same results of no sufficient pressure build up. SD the unit manually.

Aug - Sep 2010

Shift the AFV and back flush the pump • Wireline confirmed shifting the AFV and there is communication between tubing and pump

• Injected inhibited seawater into casing and started the ESP, no fluid observed at surface

• Increased the frequency, found fluid at surface. Stopped injection into casing, fluid decreasing

• Shutdown ESP manually

Nov 2010 Bullhead diesel and inhibited sea water through coil tubing to:

• Confirm the current position of AFV

• Dissolve any greasy or sticky material might be around intake of the pump and in the meantime clean the pump.

No fluid at surface. Shutdown ESP manually

Dec 2010 Pumped inhibited sea water through CT and jar up AFV using wireline shifting tools to ensure the AFV is fully open to the tubing. By jarring up the AFV, it is expected any blockage in the AFV path can be removed.

No fluid at surface. Shutdown ESP manually

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Figure 1 – CT-ESP Candidate Selection & Workflow

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Figure 2: Initial Well A Completion

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Figure 3: Well A completion post 2008 workover

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Figure 4: Completion Post 2011 Workover