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Lagan field was discovered in 1988 and is located in South Sumatra, Indonesia. Lagan is a gas field that consists of 30 wells and produces from 7 different sand layers with three faults. Along with reservoir pressure depletion, the pressure system was reduced as a strategy to maintain the gas production. In 2009, it was discovered that sand was being produced and was eroding surface control equipment during system conversion from medium pressure to low pressure. Due to limited core data, the initial challenge for conducting a sand control study was to identify which wells and which layers were producing the sand. To resolve this problem, four wellhead de-sanders were installed at four different wells, all of which produced from different sand layers. The next challenge was to find and apply a suitable sand control method by considering the urgent need to accelerate the application of sand control, limited well accessibility and rig mobility due to field location and road conditions, cost and application effectiveness. Wellhead de-sander was eventually selected as the most suitable sand control method for this field. The design and fabrication of the wellhead de-sander were completely in-house and were continuously improved to enhance the quality and quantity of sand trapping. After one year’s application, the wellhead de-sander has proven its effectiveness by reducing the amount of sand carried out to the station, decreasing production separator downtime, and eliminating surface control equipment failure cases. Until now twelve wellhead de-sanders have been installed in Lagan field to increase gas production reliability, with a total cost saving of up to USD 648.000. This paper elaborates on the road map for the sand control study and its application in a multi- layered reservoir gas field with limited subsurface data, explains how well-modeling was used to estimate the strength of sand consolidation, and describes the step by step process for optimising wellhead de-sander design.

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Optimization in brown field developments is always challenging in terms of cost. One of it is XY Field, Rimau Block, South Sumatera with more than 70% of artificial lift is Electrical Submersible Pump (ESP). At ESP wells that are already running at maximum operating frequency of 60 Hz, some are still having problems to optimize their potential. The option to replace the pump with a higher rate is less of an option due to high cost. This leaves an opportunity to gain oil production by increasing frequency above 60 Hz. Upon discussion with the ESP Principal on the risks and possibilities, a trial was then planned for 3-wells. Candidates are selected from the list of ESP wells with the following criteria such as already operated at 60 Hz, still have sufficient fluid submergence, and based on simulated motor load at 70 Hz is still at safe motor load level. Frequency was increased gradually while continuously monitoring ESP Parameters (motor load, voltage and harmonic). It is also necessary to monitor the cable temperature as it is directly affected by the frequency changes. For each frequency increment, a well test is also performed to monitor the production changes. The trial was done on 3-wells (XY-364, XY-370 and XY-378), with the following promising results. XY-364 and XY-378 successfully reached the targeted 70Hz, while XY-370 stopped at 65Hz due to a cable temperature issue. Oil gain from this optimization was 48 BOPD with 1,043 BLPD and similar BS&W profile. ESP operation still normal until present day with all parameters at acceptable range. There were, however, challenges found during the trial. Cable temperature of XY-364 increased at junction box and found cable scun loosen. The problem was solved by replacing the cables. For XY-370, found temperature increment at moulded case circuit breaker during trial at 65 Hz. It was decided to hold at existing frequency. Unbalanced motor load at XY-364 and broken capacitor at XY-370 occurred at Harmonic Filter. The problem was solved by replacing the capacitor. The trial proves that we can operate ESP higher than base frequency (60 Hz) and resulted in decent oil gain. This opens an opportunity in ESP optimization above 60 Hz at an even larger scale.

In October 2019, electrical submersible pump (ESP) XY-107 experienced an overload shutdown. Troubleshooting actions have been conducted such as reverse rotation, used rocking method, voltage boost, inject gas through the annulus, and even fluid circulation, yet still failed to reactivate the well. Pump stuck condition was suspected and urgently need a solution. A study was performed to determine the cause of pump stuck. XY-107 is produced from limestone formation, therefore suggesting possibility of scale deposit formation in this well. Upon physical inspection inside the well's flowline, lump of deposit was recovered and suspect similar material could have occurred inside the pump. Rig intervention is a common solution for the ESP pump stuck condition. However, it required high cost (around 80,000 USD) and a longer well service job period up to 5 days. With scale deposit as the suspect, an unconventional solution was proposed to soak the well with acid to dissolve stuck-material by rigless operation. It was much cheaper than rig intervention (only about 4,000 USD) and with a shorter time of 1 day. Yet, acid selection is critical to avoid material damage during operation. Since conventional acid system is known to be corrosive to the metal components, hazardous, and difficult to handle; chelating acid was chosen as an alternative since it is known as a metal-friendly and able to dissolve carbonate and iron deposit. Treatment to address pump stuck situation was executed in March 2020. The chemical treatment was injected by pumping and circulating chelating solution from tubing to the annulus. ESP then soaked for 48-hours long. The treatment has successfully revived the well. It produced with no significant issue for 8 months and even double the oil production. This successful treatment proves chelating technique is safer for ESP and able to regain well production. Significant cost saving up to 76,000 USD was realized by avoiding rig intervention and shortening time of well services. Detailed study, laboratory testing, treatment procedure, and further analysis are discussed in this paper. Chelating acidizing is an uncommon acid system to stimulate carbonates and sandstone in our operating area. Since its successful performance during the trial, more acid campaign using chelating was conducted to enhance oil production. However, this acid system was never been tried as a solution treatment for pump stuck condition and the case of well XY-107 was the first time in the company's history.