VICO Indonesia is an Oil and Gas company which has operated mature fields located in the onshore part of East Kalimantan which has been on production for over 30 years. The fields are dominated by gas reservoirs with a much lower presence of oil reservoirs. Production mechanisms cover from natural depletion to weak and strong water drive, particularly in some of the shallow areas. Recent well completions include single and dual slimhole monobore.The field is a perfect combination of stratigraphic and structural traps with more than 4000 sandstone reservoirs where around 450 of those are oil reservoirs. The oil recovery factor for these reservoirs is in the range of 10-30%. Oil development in this fields performed using gas lift as the main artificial lift while several wells still flowing naturally. Coiled tubing gas lifted (CTGL) wells contributes to 60-80% of current oil production of 8000 BOPD.Totally, 50 CTGLs have been installed in VICO Indonesia where most of those considered successful. The main problem found related with initial operation after installation. Lesson learned has been summarized including the design and the procedure for initial operation. Coiled tubing gas lift design and troubleshooting are rarely found in literature. Thus, this paper presents the detail step by step design and how to troubleshoot the possible failure during early operation. This approach exhibits a real benefit to recover more untapped hydrocarbon with more aggressive program.
Tangguh is a Liquefied Natural Gas (LNG) greenfield development located in Bintuni Bay, Papua Barat, Indonesia. There are fourteen wells that are designed to produce up to 240 MMcf/D per well. Sand and other solids from the reservoir are managed with a comprehensive, holistic strategy to provide operational assurance from the sandface to the processing facility.The Tangguh gas wells are identically completed in the Roabiba formation with seven inch monobore cased-hole perforated completions. Each well flowline is equipped with a dedicated non-intrusive acoustic sand detector and wet gas flowmeter. Well bottomhole pressures are monitored continuously with permanent downhole pressure sensors.Extensive log and core analyses suggested that Roabiba formation competency was sufficient to not require downhole sand control. Similarly, surface processing facilities and flowlines were constructed with a design basis of very low levels of sand and other solids production. Produced liquid yields are low and formation water is not expected until the latter years of field depletion.An integrated sand management strategy has been implemented since pre-startup with an underlying theme of formation sand prevention. Following completion, all wells were methodically cleaned up to remove potential formation drilling damage and other completion related debris. Wells were initially cleaned up to 100 MMcf/D with rig testing equipment and later ramped up to their maximum allowable rate to the permanent production facility.Measured formation sand production is negligible to date. Real-time well performance is monitored continuously and managed with rigorous constraints to minimize potential sand and other solids production. Detection of acoustic signals over a pre-determined limit are investigated and followed up with further action as necessary.
Managing big gas well requires careful monitoring to ensure optimum wells production within their operating envelopes whilst continuously obtaining production data. Such data improves subsurface understanding over time and become a basis for optimization exercises, wellwork initiation, and quick corrective actions. Tangguh all-inclusive well surveillance integrates various daily data analysis into an efficient well surveillance process. It essentially looks for both early problem signs and improvement opportunities, enabling ahead anticipations. Tangguh real time surveillance allows continuous parameter monitoring: pressures, temperatures, choke opening, multiphase flowrates, sand detection, annuli pressures, and system backpressure. A semi-automatic system then integrates all available data quickly and allow engineers to perform meaningful analysis timely. The integration is a significant upgrade over the past surveillance practice, where typically more time spent on data gathering instead of the analysis; and missing anomalies that happened in unmonitored parameters while concentrating on a specific parameter. Combining with some non-routine data acquisitions, this well surveillance integration enables a quick and thorough well performance review and assists unlocking optimization opportunities. Three examples below demonstrate value creation from the integrated well surveillance. First example: combining real time well data and the non-routine acquisitions enable robust well productivity model construction. This has improved the understanding of each well productivity and operating limits, which upon evaluating lead to deliverability increases by simple well limits upgrade and debottlenecking projects. Other result includes assistance in defining restoration wellwork candidate. Second example: by continuous comparison between real time data and calculated performance model, the surveillance has shown its ability to detect well choke trim damage while flowing. This successfully prevented problem escalation into a more serious safety incident, such as gas release from an eroded choke valve. Third example: despite the challenges in accurate dry-gas-well liquid rate measurement, continuous water source identification is applied honoring the significant reserve it may impact, starting from routine salinity monitoring, theoretical condensed comparison against receiving facility figures, and material balance plots. All positively indicate no aquifer breakthrough yet so far.
Mutiara is a mature field located in the onshore part of East Kalimantan which has been on production for over 30 years. The field is dominated by gas reservoirs with a much lower presence of oil reservoirs. Production mechanisms range from natural depletion to weak and strong water drive, particularly in some of the shallow areas. High decline rates are very common, which results in a very dynamic and challenging environment. The main artificial lift used in this field is gas lift. However, this method is not efficient for depleted or high water cut wells. Another issue is oil wells which located in remote areas which need high investment for surface facilities including gas lift line network and sufficient pressure to lift the oil up to the surface. Therefore, more and more wells will be idle without implementation of other artificial lift systems techniques.Several downhole pumping types have been assessed to tackle these issues such as Electric Submersible Pump (ESP), Progressive Cavity Pump (PCP), and Linear Rod Pump (LRP). Considering hilly swampy conditions of the field that requires more compact type of surface unit and flexible to match displacement rate to well capability as well declines. It is then decided to use LRP to unlock oil potential in idle wells.The first installation of LRP was on September 2014 in X-1 well, this well is the first well drilled in 1982. This installation succeeds on bringing back the well on production. The application of LRP provides opportunity to unlock oil potential from idle wells in this mature area thus maximizing reserve by gaining a few more hundreds barrels of oil per day during the first year.
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