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P Mosar, Nur Faizah (Schlumberger) | Ceccarelli, Tomaso Umberto (Schlumberger) | Tan, Chee Seong (Schlumberger) | Arsat, Maisara (Schlumberger) | Mohd Yaacob, Mohd Khairul Azahan (Schlumberger) | Sinanan, Haydn Brendt (Petronas) | Fabian, Oka (Petronas) | Suratman, Muhamad Farhan (Petronas) | Samuel, Orient Balbir (Petronas)
Water and gas injection are widely used techniques to alleviate pressure decline and improve sweep efficiency in brownfield reservoirs. When variable reservoir properties exist, such as permeability, pressure, and thickness, the requirements for real-time monitoring and control become crucial to ensure zonal injection target rates and volumes are achieved.
The Bokor Field is located in the Baram Delta area of the South China Sea, 45 km from the shore of Sarawak, Malaysia, in a water depth of approximately 70 m. This marks the initial use in Malaysia of a distributed temperature sensing (DTS) fiber optic cable installed and cemented behind casing in a multizone immiscible water alternating gas (IWAG) injection well. Injection profiling was monitored via the DTS across multistacked reservoirs having different horizontal permeabilities. The DTS detected injection profile patterns within each zone and enabled identification of high permeability streaks and thief zones. Inflow control valves (ICV) were then used for injection management and control.
For Bokor well, offshore Malaysia, an intelligent completion system was chosen. The well comprised downhole flow control valves with 8 choke positions, permanent downhole gauges, and a DTS cable to enable optimum injection conformance. DTS provides real-time temperature measurements along a multimode optical fiber encased in a ¼-in control line. Enhanced measurement accuracy can be achieved by placing the DTS cable as close as possible to the reservoir by installing it behind the production casing in direct contact with the reservoir formation.
Deployment of the DTS in such a way presents several challenges in the design and operational phases. The first challenge is to ensure the integrity of the cable while running and cementing the casing in a highly deviated trajectory. Special equipment was designed to ensure mechanical protection of the fiber while safeguarding the quality of the cement-to-casing bond. An innovative TCP perforating technique and cable detection system had to be developed to prevent damage to the DTS when perforating the casing. Several design interfaces and system integration tests were identified and carried out between multiple providers to guarantee a smooth and successful installation.
Preliminary results demonstrate intelligent technology for real-time monitoring of the actual injection profile behind casing, and for controlling it remotely via an RTAC (real-time acquisition and control) software solution.
Rafea, Mahmoud A. (Petronas Carigali Sdn Bhd) | Jadid, Maharon Bin (Petronas Carigali Sdn Bhd) | Subari, Ibrahim B. (Petronas Carigali Sdn Bhd) | Abu Talib, M. Nazli (Petronas Carigali Sdn Bhd) | von Pattay, Patrick (Schlumberger WTA (Malaysia) Sdn. Bhd.) | Saenz, Daniel (Schlumberger)
Abstract As production declines and watercut increases, wells are often converted from gas lift to electrical submersible pumps (ESPs). ESPs are an attractive alternative since they can achieve lower bottom hole flowing pressures. This can accelerate production and improve recovery. This paper outlines the workflow used for candidate screening, completion selection, and ESP system design of the first such conversion on the Bokor Field, offshore East Malaysia. A brief description of each methodology is outlined, potential benefits and challenges are discussed, and an assessment is presented of the life-cycle economics leading to final recommendation. Various lift technologies were considered to replace the existing gas lift system accounting for fluid properties, well depths, productivity index and economic benefit. Ultimately, ESPs were selected. A rigorous selection process identified three trial wells on the crest of the shallow ‘A’ sands. These wells are currently produced through gravel packed dual string completions. Candidates were eliminated due to wellbore dogleg severity and suspect gravel pack integrity. Reservoir simulations indicate the three ESPs will add approximately 2.8 million barrels incremental oil production over 10 years without significant watercut increase. A contingency gas lift system above to mitigate lost production during ESP downtime ensures economic viability. Finally, the ESPs are designed to provide the utmost reliability by meeting Bokor's challenging conditions. Introduction The Bokor field is located offshore Sarawak, Malaysia and is operated by Petronas Carigali Sdn Bhd (PCSB) with gas lift as a primary system for lift. Bokor is currently operating with production restriction due to insufficient lift gas and other constraints. Accordingly, the Bokor Project Management Team (BPMT), which is an alliance between PCSB and Schlumberger, is tasked with developing initiatives to improve field performance. One such initiative involved the review of the current gas lift system to determine if alternative artificial lift methods would enhance production. A team was mobilized to identify wells that would benefit from a change in the artificial lift, select the optimum lift method and provide engineering and project management for execution. The objectives for the project were defined as:Improve economics due to improved recovery and production of heavy crude from shallow reservoirs through ESPs and re-allocation of currently consumed lift gas to other existing wells Introduce a new artificial lift technology to Bokor Field and prove its value for entire Baram Delta Ensure the knowledge transfer on ESP technology and techniques to engineering teams and operational personnel for this first ESP installation in Malaysia The inception of this pilot project is considered an important milestone in PCSB's effort to establish an alternative artificial lift system for offshore production operations.
Johari, M Raimi (PETRONAS) | Jusoh, Nur Zulaikar Md (PETRONAS) | Hong, Ong Swee (PETRONAS) | Fabian, Oka (PETRONAS) | Rashid, Noor Hidayah A (PETRONAS) | Idris, Mohd Faisal Rizal (PETRONAS) | Musa, M Zarir (PETRONAS) | Balbir, Orient Samuel (PETRONAS) | Rosato, Miguel (PETRONAS) | Shaedin, Ridzuan (PETRONAS) | Teng, Chaw Kit (PETRONAS) | Riyanto, Latief (PETRONAS)
Abstract PETRONAS embarked on a new challenge to drill and complete 5 wells with high bottom hole temperature (BHT) of 180°C and highly deviated fractured carbonate with high velocity gas producers. These wells utilized 7" big bore production tubing with new material 17CR instead of the expensive cold worked 22CR duplex stainless steel (DSS). As the first application of 17CR production tubing material in the world, a lot of risks were taken into account and mitigated via various approaches from planning engineering stage until execution. These mitigation measures included the qualification of material and connection; operational details involving parties from different disciplines to ensure smooth and efficient deployment of 17CR tubing. In addition to that, optimization opportunities were explored to further increase running efficiency and reducing flat time while ensuring tubing integrity is intact. The successful deployment of 17CR were attributed to the following: Connection modification from JFE BEAR to JFE BEAR DR-PK to minimize the risk of galling around the metal-to-metal seal area on the newly developed 17CR CRA material Tubing was racked back in double joints per stand offline during installation using offline activity cantilever (OAC) deck available on a tender assisted rig to improve running time Utilization of side door elevator instead of single joint compensator to enable running tubing in double. Usage of Flush Mounted Slip (FMS) dressed with pre-qualified low penetration dies, to ensure sufficient gripping on the 17CR tubing OD surface without being affected by the surface scale which is known to have with high hardness value Usage of low penetration dies instead of non-marking type hydraulic tong to reduce tubular running cost With the above mitigation measures put in place, the project was delivered with high efficiency in terms of tubular running speed achieving up to 14 joints per hour on 7" high alloy CRA tubing with extremely low number of rejection rate (0.3%) for the entire project. Utilization of 17CR as an alternative to 22CR DSS has also contributed direct cost saving of up to USD 8.2 mil to the project.
Zulkapli, Mohd Hanif (PETRONAS Carigali Sdn. Bhd.) | Salim, Muzahidin Muhamed (Schlumberger) | Zaini, Muhamad Zaki (Schlumberger) | Rivero Colmenares, Maria Elba (Schlumberger) | Curteis, Charles (Schlumberger) | Sepulveda, Willem (Schlumberger)
Abstract Gas lift has been the primary artificial lift method for wells in an offshore brownfield in Malaysia for the past 30 years. However with depleting and unstable gas lift supply coupled with the increase in water production, an alternative artificial lift strategy needed to be developed. A revisit to the Field Development Plan (FDP) in 2003 has found that Electric Submersible Pump (ESP) could be the solution to overcoming the field's overwhelming dependency on gas lift. During a workover campaign in 2008, 3 ESPs were installed – marking the first production ESP in Malaysia. The ESPs have increased the well production from the gas lift baseline production and on top of that, there is a 66% additional incremental production from the re-allocation of approximately 1 MMSCFD of lift gas from the ESP wells. The success of the three ESPs has developed interest from the field operator to have more units installed. By end of 2011, a total of 5 ESPs has been installed in the field. They consisted of conventional ESPs, followed by an ESP in a pod with a Distributed Temperature Sensor (DTS) cable and a dual ESP with bypass tubing. Another 3 installations have been planned in the near future. The operator is also looking at the potential and feasibility of a rigless deployment for the ESP - either by using coiled tubing or a standard slickline service. In an offshore environment where rig cost and rig availability is of concern to well uptime and project economics, alternative ESP deployment has been seen as the next frontier of ESP technology to increase revenue. The transformation of artificial lift strategy in the field – from gas lift to ESPs - has been very progressive and profoundly significant to the operator's continual technological advancement in the industry. Introduction Bokor field is located 45 km offshore Sarawak, East Malaysia. It was discovered in 1974 and started production in 1984. The field reaches its peak production of 30000 barrel of oil production in 1990. Bokor field comprises of 3 production platform which are BODP-A, BODP-B and BODP-C, one processing platform (BOP-A) and one compressor platform (BOK-A). BODP-A, BODP-B and BOK-A are interconnected by bridge link while the BODP-B and C are only accessible via boat. Power generation is located in BOK-A and limited to BODP-A and BOP-A. The rest of the production platforms have solar power system limited to the platform's Supervisory Control And Data Acquisition (SCADA) system and basic utility. Due to the field unconsolidated formation sand, all of the wells in the early years were completed with cased hole gravel pack. Strong water aquifer in Bokor provides good and continuous pressure support, however increasing water cut becomes a severe problems to the surface facilities and increased demand to the lift gas. As an initiative to boost productions in the field, the operator ties a new relationship with Schlumberger to be its technical partner in 2002. The main objective of the partnership is to produce the incremental oil from the field. Bokor field comprises of more than 100 strings of oil wells with half of them is idle and the rest are producing on gas lift with several string on natural flow.
Abstract This paper will outline and discuss the processes involved from planning to conceptual design, detailed design, equipment preparation and onsite execution that has contributed to the successful offshore installation of Malaysia's first dual ESP system. It will also highlight the challenges and issues encountered throughout the project. The well was originally completed in 1989 as a single producer with gas lift. It is closed in 2004 due to high solid production. A workover operation was carried out in end of May 2011 to revive the well. The current producing zone was plugged and abandoned and the shallower producing interval is opened up and completed. Instead of continuing with the status-quo, gas lift strategy the well is completed with a Dual ESP system with bypass tubing, making it the first ever dual ESP installation in Malaysia. Gas lift has been predominantly used as the main artificial lift strategy in the region. It's relatively ‘cheap’ resources and simple application has been the main driver for oil operator to continue using it as their preferred option. However as the water cut increases and lift gas supply become limited there is a need to have a look on the so called ‘commodity’ artificial lift application. ESP has been seen as one of the most attractive alternatives. The field's first conventional ESP installation with a backup gas lift system in 3 wells was installed in late 2008. In 2010 another ESP with pod configuration was installed. Ever since then, Bokor Project Management team has started to explore on the advancement of ESP system in order to find the optimized design for Bokor Field. However there are several challenges to be addressed. Justification to use a dual ESP system rather than a conventional gas lift system or single ESP configurations that has been done previously in 4 other wells, especially in term of initial cost. The complex installation of a dual ESP system complete with bypass tubing and gas lift backup system which is not a common practice in the area Design considerations and challenges for a successful installation. A complete design of a dual ESP for well specific application. Installation challenges of Dual ESP system with bypass tubing and backup gas lift system utilizing a hydraulic workover unit which has limited handling capacity compared to a conventional rig. Surface requirement and limitations of the existing facility for ESP commissioning and startup. Among others, the paper will discuss on the justification and technical solutions that have been proposed for the installation of the dual ESP system in Bokor field. Lesson learned from the project is also compiled in this paper for any future similar installation in the field