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Amsidom, Amirul Adha (PETRONAS) | Ghonim, Elsayed Ouda (PETRONAS) | Alexander, Euan (PETRONAS) | Kuswanto, Kuswanto (PETRONAS) | Abdullaev, Bakhtiyor (PETRONAS) | Hassan, Hani Sufia (PETRONAS) | Ishak, M Faizatulizudin (PETRONAS) | Rajah, Benny (PETRONAS) | Gunasegaran, Puvethra Nair (PETRONAS) | Ayad, Kamal (Cornerstone for Business Development) | Madon, Bahrom (PETRONAS) | Hamzah, M Amir (PETRONAS) | Zamanuri, Kautsar (PETRONAS)
Abstract About 80% of brownfields in Malaysia use Gas Lift as the artificial lift method. Though it is widely used, the operators are facing numerous challenges which include shortages in gas lift source and compressor reliability issues. Consequently fields’ productivity is impacted and results in higher operating expenditure. A case of change from Gas Lift to ESP was studied however due to high rig costs many of these the projects are uneconomic. Given this is the case PETRONAS had been researching the use of high speed slim, power- cable deployed ESPs for installation inside 2- 7/8" and 3-1/2" tubing (TTESP-CD). The challenge was to develop a deployment method using intervention techniques to comply with process safety requirements and installation over a live well without any workover rig. The associated technologies to enable deployment and operation of the ESP were identified, modified, developed and qualified as required in order to meet API 6A, API 14A and ISO 14310. In order to meet the project objectives and derisk technical uncertainties, an onshore test run and offshore pilot were planned. These ensured the design requirements of the key deployment technologies met relevant API and ISO standards; 1) wellhead adapter for cable exit and load handling 2) the anti-rotation anchor packer and 3) the insert safety valve, 4) wireline unit, 5) pressure control equipment. Each of the technologies developed or modified are key components of the deployment technique. Through the onshore testing, the deployment procedure and running equipment were improvised to fit the offshore pilot installation. The deployment of the TTESP-CD system offshore was a success; the ESP was installed within 3-1/2" 9.2ppf tubing to a depth of 1752ft over a live well using the modified deployment package. The actual ESP deployment took around 5days including rig up/down of the deployment package. Running the ESP to depth only took around 8hrs including setting the insert safety valve. Major time consuming events were assembling the ESP, cable space- out, cable termination/splice, landing hanger and cleaning out the electrical connections. Looking forward; this is a technology PETRONAS see great value in for Malaysian and international assets. Currently there are plans for four more installations in 2018 and a minimum of five installations in 2019. The PETRONAS led team have overcome challenges the industry has faced for many years with regards to this type of ESP deployment by investing in R&D and committing resources. By developing this technology PETRONAS and its technology providers have officially opened up market for low cost ESP deployment which is a significant step change to conventional practice. This will be of great benefit to the upstream oil and gas industry, particularly for offshore assets with little infrastructure.
Zamanuri, Kautsar (PETRONAS) | Yip, Pui Mun (PETRONAS) | Radzuan, Nurul Asyikin (PETRONAS) | Salleh, Nurfarah Izwana (PETRONAS) | Ghonim, Elsayed Ouda (PETRONAS) | Alexander, Euan (Ex-PETRONAS) | Bakhtuly, Daniyar (NOVOMET)
Abstract Most Malaysian oil production is heavily reliant on gas lift. Aging assets experience declining lifting efficiencies due to depleting reservoir pressure and increase in water cut. This impact PETRONAS' capability to deliver national hydrocarbon production targets. New developments and further improvements to gas lift facilities are likely to erode the economic value of assets without even considering the potential time impact due to the complexity in delivering gas compression upgrades or gas import projects. PETRONAS' primary goal within Malaysia is to sustain production and maximize the remaining recoverable reserves. To realize this target it is widely acknowledged that the company must think differently. Alternatives to gas lift have been considered for rejuvenation of brownfield assets and development of marginal assets using a ‘fit for purpose' approach resulting in some relatively low Capital Expenditure (CAPEX)/Operating Expenditure (OPEX) solutions. One such method identified was Through Tubing Electrical Submersible Pumps - Cable Deployed (TTESP-CD). TTESP-CD technology is a game changer that can challenge the boundaries of traditional engineering with a truly rig-less deployment of an ESP system with full compliance to API/ISO requirements and demonstrating up to 70% cost savings over conventional offshore ESP installation methods. The TTESP-CD innovation helps in improving the asset value through gas prioritization, gas lift reallocation, flaring reduction and increase in lifting efficiency. TTESP-CD is also in line with the company digitalization concept due to the baseline data available from surface and downhole equipment. This technology has been declared a success through pilot deployment in an offshore field within the Sarawak Basin with an incremental gain of 250BOPD, 0.3MMSTB in reserves acceleration and 22 months run life as of Feb 2019. This has been a key step for building confidence in the wider application of the technology. Lessons learnt and best practices from the pilot implementation have been applied to ongoing and future projects and serve as a good foundation for further development of the technology. To date, approximately 20 candidates for the TTESP-CD application have been identified for replication in Malaysia within the next 2 years across 3 regions. There are various challenges faced when implementing this technology on aging offshore assets that was never designed for ESPs which include; space availability for deployment equipment and surface electrical equipment, power availability and distribution, instrumentation, data transmission, structural integrity and operational mind set. PETRONAS sees a bright future for TTESP-CD application and technology which includes layer to layer matrix dump flood, interim production and well unloading/DST well unloading.
Radzuan, Nurul Asyikin M. (PETRONAS) | Salleh, Nurfarah Izwana (PETRONAS) | Chandrakant, Ashvin Avalani (PETRONAS) | Rusman, Liyana (PETRONAS) | Zamanuri, Kautsar (PETRONAS) | Bakar, Azfar Israa Abu (PETRONAS) | Yip, Pui Mun (PETRONAS) | Jamaluddin, M. Helmi (PETRONAS) | Ghonim, Elsayed Ouda (PETRONAS) | Nambiar, Vijay (Novomet) | Alexander, Euan (Artificial Lift Solutions)
Abstract Following the first pilot success of the truly rigless 3-1/2" tubing cable deployed ESP (TTESP-CD in offshore field of Sarawak Basin, PETRONAS has taken steps to further advance in the technology development and application through more replications within Sarawak and Malay Basin. PETRONAS had been looking into a strong business case for the TTESP-CD technology for a wider application throughout Malaysia region by looking at fields with strong/moderate water drive and low bubble point pressure besides having other limitations on the platform including the facilities reliability issues. TTESP-CD are to be applied widely in Malaysia with more flexibilities in design and improvement towards the subsurface equipment, installation equipment and procedures. With the challenges in the existing completion and production requirement for replications, based on the lesson learnt from the pilot implementation, multiple improvements to the system have been done including; 1) A High Rate Slim Pump with Flexible Application 2) Alignment Tool for Cable Hanger Orientation. With this in place, more opportunities identified for the candidate selection which improve the installation philosophy specifically in dual string applications and enhance the efficiency in installation procedures. Case studies of TTESP-CD replications in Malay & Sarawak Basin for Field T, Field B and Field P presenting the best case for TTESP-CD application with improvement to design, equipment and application. These will bring additional value to PETRONAS with estimated production gain of ∼1.5 KBD and up to 1.2 MMSTB reserves to be monetized with additional value saving of up to RM 6 Mill. Besides the subsurface challenges, aging offshore assets brings a lot of challenges, especially on the space availability, structural integrity, power availability and distribution, instrumentation and data transmission. This requires an integrated approach from multiple disciplines in delivering the studies as per required within the targeted timeframe.
Scarsdale, Kevin (Schlumberger) | de Pieri Pereira, Domitila (Schlumberger) | Garber, Matthew (Schlumberger) | Goh, Kim Hoo (Schlumberger) | Kee, Bernard (Schlumberger) | Gastaud, Nicolas (Schlumberger) | Simon, Anish (Equinor) | Joseph, Jeswin (Equinor) | Cook, Walter (Chevron)
Abstract In the Gulf of Mexico, the rapid pressure depletion and reservoir depth of the Lower Tertiary intervals lead to low oil recovery. A high-reliability, through-tubing subsea electrical submersible pump (ESP) system that takes an integrated approach to production optimization will enable producers to cost-effectively extract more hydrocarbons from the increasingly challenging reservoirs in today's subsea assets. The potential increase in production depends on the maximum drawdown pressure limitations of both well casing design and rock strength. ESPs in deepwater fields are also considered to be an enhancer rather than an enabler by extending the production plateau 5 to 8 years after initial well/field startup with natural flow and seabed boosting. Hence, a robust ESP system that can be installed and operated a few years after field startup without a workover for replacing the upper completions. A robust, reliable ESP would unlock additional value to deepwater operators by delaying CAPEX and eliminating ESP failures, such as degradation of components due to high-pressure/high-temperature (HP/HT) cycling, during the first few years of nonoperation. Designing ESPs for deepwater application is a multidisciplinary challenge and needs to be approached from a full system-reliability standpoint rather than improvements to the ESP hardware alone. Implementation of ESPs in deep water requires both upfront planning at a full-system level and high degree of flexibility for installation, deployment, and retrieval. Finally, because the impact of an unplanned ESP failure is significantly detrimental to project economics, efforts to improve robustness of the ESP hardware must be complemented with automation of ESP operation to reduce or eliminate operator-induced failures. Recent industry improvements in machine learning and predictive analytics need to be leveraged to implement condition-based monitoring of ESPs to better anticipate failures and plan for replacements and/or adjustments to extend the life of degraded units. A collaborative project was undertaken to develop the concept of an alternatively deployed through-tubing ESP (TTESP) system targeted for deepwater subsea operations. The goal was to reduce intervention costs, which, together with ESP run life, are the primary factors influencing the economics of subsea ESPs, including conventionally deployed through-tubing ESPs. The project scope encompassed the downhole hardware, from immediately below the subsea tree through the upper completion, as well as deployment and retrieval equipment and methodology. Economic analyses of subsea fields were conducted to identify the factors contributing to intervention costs so that alternatives could be developed. Multiple concepts were evaluated, and the proof-of-concept system was selected based on superior economic return compared with the baseline. During this proof-of-concept phase, significant testing of key technologies was conducted. The studies showed that conventional intervention vessels and methods will not reduce the intervention costs associated with TTESPs. Lighter vessels together with technologies and methods that minimize intervention time and frequency—and, consequently, reservoir damage and deferred production—are the answer. Eliminating the wait for an available offshore rig is also a key factor in improving overall production economics. The proposed alternatively deployed TTESP system and its associated deployment methodology could reduce the intervention time by half and eliminate reservoir damage. This unconventional deployment could be conducted with lighter service vessels, further reducing intervention costs.
Abstract Artificial Lift Company Ltd. (ALC) and ConocoPhillips Company in 2004 initiated a 5 year development program to have a fully deployed wire-line through tubing electric submersible pump (TTESP) with a down hole 3 phase electrical wet connector. ConocoPhillips Alaska had immediate applications for this technology in its Alaska business unit, West Sak asset. The wells in this asset are multi lateral and suffer from large amounts of sand production which settles in the mother bore restricting production flow to the ESP. Historically, a Rig would be required to pull the tubing and ESP equipment to allow access for wellbore intervention. ConocoPhillips has had 10 years of experience with wireline pumps which allowed pump replacement of sanded pumps but did not provide for rigless cleanout of the casing below the ESP. The ability to pull the entire ESP through 4.5" tubing providing an unobstructed tubing string for placement of lateral re-entry modules and to conduct coiled tubing cleanouts of sand in the casing was highly desireable. This was also aligned with ALC's objective which was to make the system compatible with the most common wellbore architecture. System Requirements:Wellbore architecture; 7 in 26 lb/ft casing and 4–1/2 in 12.6 lb/ft tubing. Full bore access to the well - minimum tubing ID of 3.75 in, when the wire-line ESP components are retrieved. Motor(s) to produce 300kW (400HP) from a maximum diameter of 3.80" OD Down hole 3 phase wet connector rated at 5 kV and 125 A Equipment string target length less that 47ft to enable live well deployment using wire-line lubricators. The string weight also had to be less than 1500 lbs. to allow the use of slick line rather than braided line. Ambient operating conditions 5000psi and 150ºC (302ºF) The wire-line string had to be able to deploy an industry standard ESP gauge. Five Year, Three Phase Development Program: Phase 1: - Key Components EvaluationProve permanent magnet motor technology Prove electrical wet connector technology. Phase 2: - Component & System Design and TestingConstruction of a 300ft test well with all the necessary ancillary equipment in ALC's Great Yarmouth (GY) facility. Build surface testing cells for extended testing of the motor and wet connector assembly at elevated temperatures and pressures. Design, manufacture and assemble a wire-line 3 phase wet connector, motor and ESP system. Endurance testing of Components and System in GY. Phase 3:- Field Test HardwareManufacture a field test system with a complete back up Perform full stack up testing in the 300ft test well Field test equipment in a live well (Odessa, Texas) March 2009 This paper will describe in more detail each phase of the project, a detailed description of the hardware and the potential economic/commercial value it offers to operators of ESP systems, particularly in locations where rig costs are high or rig availability is limited.