Continuous gas lift system is currently widely used as artificial lift in Kaji-Semoga Field, in fact at about 46% of total producing wells. The average depth of gas lift wells in Kaji-Semoga is 3,200 ft, utilizing 2 to 5 conventional gas lift valves in a single production string. Common problems experienced when optimizing gas lift wells in Kaji Semoga field are instability of flow due to fluctuation of gas lift injection rate and pressure, limited gas injection volumetric rate, and limited compressor discharge pressure that leads to limited casing head pressure at well head, especially for remote wells with high tubing pressure at injection point.A new injection valve type, venturi orifice gas lift valve with breaking-out gas device, has been studied and proposed as a solution to the aforementioned problems. This type of valve has been installed as gas lift injection valve at some pilot wells by using slick-line unit. The aim of venturi orifice is to reduce pressure difference between casing (upstream) and tubing (downstream) at injection point and to deliver a greater amount of gas lift injection at the same casing head pressure (compared to traditional orifice valve). Meanwhile, the aim of the breaking-out gas device is to break the injected gas into very small bubbles and homogenize with the liquid so that flow stability can be achieved.Selected candidates for pilot wells are the ones with high productivity index (PI), high flowing pressure gradient (above 0.18 psi/ft) and limited gas lift manifold pressure. Well modeling and simulation have been conducted for these selected wells using production optimization software to predict gas lift well performance after installation of new injection valve, whereupon the simulation result is matched with actual data.Applying venturi orifice gas lift valve has produced successful results: the liquid rate of the pilot wells has increased by about 40%, with 30% gas injection rate increment under the same conditions. Computer simulation also provided similar results to the actual well performance and met expectations. The pay-out time (POT) of this project was less than 2 days.

The Kaji-Semoga fields in South Sumatra, Indonesia, are mature, waterflooded oil fields with ESP's in more than half the wells. To minimize oil deferment due to down-hole ESP problems, an ESP-gas lift hybrid was implemented in 2009. The idea was to install gas lift as a backup so the well could be kept on production, albeit at reduced rate, until the ESP could be serviced or replaced. During the period 2011-2012, 97 wells had the hybrid lift system installed and ESP problems occurred 23 times in these wells. The availability of the ESP-gas lift hybrid minimized oil deferment and allowed approximately 24,000 bbls of oil to be produced while waiting for the ESP to be serviced or replaced. However, the previous hybrid design used just a single gas lift valve as an unloader and injection point. Performance analysis of the previous design showed that the gas lift performance could be optimized if the injection point was, on average, about 300 feet deeper. But that would be too deep for unloading, so the gas lift hybrid system was redesigned by incorporating two gas lift valves, one a shallower unloading valve and the other a deeper injection valve. Between April 2013 and March 2014, twenty-four wells had the redesigned ESP-gas lift hybrid installed. Performance analysis of the design was conducted at KS-XXX well when it had an ESP down-hole problem. After the redesigned gas lift was activated, it increased drawdown by 121 psi compared to the previous design, kept the liquid lifting to 57% of ESP production rate (compared to 25% of ESP production rate with the previous gas lift hybrid design) and minimized oil deferment leading to 540 bbls of additional oil production in this one instance. Analysis of the overall performance of the redesigned ESP-gas lift hybrid is onging, but results are similarly good.

X field was discovered in 2001 and started producing in 2003. The formation is limestone supported with large aquifer. Main challenge is that wells must be produced with critical rate limitation, if a well is produced too hard, water coning and water breakthrough can occur, then oil production will disappear, as happened in one of X's well. In 2011, several wells were becomes ceased-to-flow due to an increase in watercut value, then pumping units were installed on these wells. However, due to recurrent mechanical downhole problems which limit effective production days, a new initiative is required to overcome these issues. After thorough analysis, ESP was chosen as best-fit artificial lift considering its versatility in deviated wells and high deliverability. In 2017, pilot phase of ESP implementation started in X-D4 well, which gave 150 BOPD average oil gain. Learning from the success of X-D4, comprehensive production strategy using ESP is considered crucial for optimum recovery. To support this strategy, an integrated optimization study with reservoir simulation model was used instead of analytical method to obtain more reliable production forecast. History matching was carried out from initial production data in 2003, a good match in liquid-oil-water-pressure data was successfully obtained, but poor match was occurred on gas production rate, this was ignored due to high uncertainty on gas measurements. The outcomes of simulation study were ESP well candidates, optimum production rate target and proper timing of ESP installation. The next step was the preparation of ESP which consists of the design and procurement of ESP. Following the ESP installation plan, it was also decided to increase power generation capacity at current surface facilities. Currently, 7 out of 10 ESPs have been installed. Power plant upgrading and overhead line installation to support ESP have also been carried out. The average oil gain obtained was 700 BOPD with cumulative of 160 MBO (from 2017 – until 2018). This optimization case will contribute 1.5 MMBO additional reserve from "do nothing" case. Economic evaluation shows a very good viability with significant additional gross revenue. This optimization project has succeeded in reducing oil deferment from ceased-to-flow wells and extending the field's life. Good collaboration between each part (subsurface and surface) in this project has succeeded in producing significant oil gains. Continuous monitoring is still needed to further match optimization forecast with actual conditions. Long-term plans, some improvements are still needed in the reservoir model, one of which is OOIP value, there is a possibility that the actual X OOIP is bigger than the one in the reservoir model.

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