Kaji Semoga (KS) field has produced primarily from limestone and has until recently contained sufficient gas for gas lift usage. However, KS gas production is declining rapidly: it is estimated that by 2013 it will produce insufficient gas. As a result, some new forms of artificial lift are being considered to replace gas lift, and since the end of 2008 new ESP and HPU projects have been carried out with the aim of such a new form of lift. As a result of implementing these projects, ESP wells will be the dominant artificial lift for production wells in KS, contributing to approximately 70% of total oil production On the other hand, there are risks of downtime associated with the use of ESP. The main risks concern downhole problems, which need rig deployment, and electrical problems, which cause the ESPs to shut down. Fixng these problems may require a considerable amount of time - several days or even weeks - due to reasons such as unavailability of a rig and/or spare parts. This will inevitably result in loss of oil .production. To avoid such production loss, an ESP / gas lift hybrid system has been implemented, whereby gas lift is prepared as a backup. This hybrid system consists of an ESP unit installed along with a gas lift system in single tubing, with no packer and 1 (one) (screen orifice) gas lift valve, 1 (one) sliding sleeve door, and 1(one) complete ESP unit. All ESP wells in KS (currently 70 wells and counting) now use this configuration. The gas lift hybrid system has been used as backup during ESP downtime. This configuration can produce 35% of liquid compared to normal ESP liquid production, and as a result an oil loss of 4400 bbls was prevented during 2009.
A hydraulic fracturing stimulation campaign has been successfully conducted in Rimau block. The stimulation was applied in tight KTLS sandstone formation with permeability within the range of 5-10 mD and also conducted in medium permeability multilayer LTAF sandstone (>10 mD) to bypass nearby wellbore damage.The purpose of this paper is to share best practices and lessons learnt from the hydraulic fracturing campaign, which commenced in 2003. The campaign was divided into three stages, with the aim of continuous improvement. The first stage was conducted in 2003, when a trial with a generalized design was conducted. Later, the second stage was conducted during the period 2004-2009, when a hydraulic fracturing campaign with improved design was carried out. Finally, the third stage was conducted from 2010-onwards, when the campaign was improved by emphasizing operational excellence and technological diversification.Beginning with Stage 1, hydraulic fracturing was performed in 13 wells in KTLS using typical fracturing design. An increase in production from each characteristic of formation was observed. Following the success story of Stage 1, a campaign was conducted in Stage 2 by proposing a plan of development for 50 wells to generate an optimization of the fracturing design. Stage 3 consisted of performing further optimization through technology diversification to overcome pressure depletion and operational collaborations. Furthermore, fracturing was also applied to higher permeability sandstone formations to bypass nearby wellbore damage.The continuous improvement during all stages resulted in an increase in oil recovery of 10 to 25% in tight formation and 30% in higher permeability formation, with an oil gain ranging from 80-500 BOPD and a typical yearly decline of 40%. In the future, hydraulic fracturing will be applied to face further challenging conditions, such as tight gas, tight oil and shale gas.
During this low oil price era, E&P operators are challenged to reduce operating costs by evaluating their production system. Integrated production model (IPM), which combined subsurface model and surface production system, is a tool that can be utilized to evaluate the existing production system and to arrange the upcoming production strategy. This paper focuses on Kaji-Semoga oil field which consists of three field processing stations, three compressor stations, 130 ESP and 63 gas lift (GL) wells. The system evaluation started with evaluating the total GL injection required for all GL wells to observe the opportunity to increase the oil production or reduce the active compressor. This required gas lift performance curve for each wells with sensitivity to the various well head pressure. The ESP, as equipped with variable speed drive, can be optimized in accordance to the pump capacity and facility constraints. The artificial lift reliability was also evaluated to reduce the oil deferment and to foresee the next production strategy. The IPM for Kaji-Semoga was built to integrate those issues. Based on the IPM, the total GL injection rate can be reduced by up to 17% while maintaining the total oil production. With the aim of cost optimization by saving the gas fuel and reducing compressor cost, then the gas lift compressors had been shut down and relocated to another asset. As the result, 24% of total annual compressors cost was saved. From the artificial lift reliability evaluation shows that GL system reliability was reduced along with the gas shortage, whereby contributed 71% of total oil deferment. The artificial lift conversion from GL to ESP then selected as a solution. The strategy for shutdown the next gas lift compressors was then generated in accordance with the artificial lift conversion schedule and the gas lift network distribution. To overcome the limitation of liquid handling capacity at the field stations due to the conversion project, the IPM could optimize the GL and ESP simultaneously thus total fluid production can be maintained at a minimum level by continuing to retain the oil production. The paper describes some of lesson learned in constructing and utilizing the IPM as an effective tool, not only to optimize the existing production system, but also to generate the future production strategy, cost reduction opportunity and operation maneuver.
Kaji-Semoga (KS) field, a mature field located in South-Sumatra, requires more efficient production operation to reduce production lifting cost. Since 2008, KS field has been experiencing gas shortage due to the decline in associate gas production. As a result, some of the gas lifted producer wells need to be converted to another type of Artificial Lift (AL). After various studies and trials, it was concluded that ESP (Electrical Submersible Pump) was the most suitable alternative. Currently, the AL system is dominated by ESP with total deployment 140 of 190 producing wells, contributing 70% to the field's overall oil production, i.e. a total of 9,500 BOPD. Furthermore, KS field purchases gas as fuel for the electricity system, which is mainly consumed by AL. Therefore, efforts have been made to evaluate and obtain significant cost reduction in power consumption of ESP through power efficiency assessment and feasibility of new technology implementation. Power efficiency assessment for ESP application becomes a promising attempt to reduce ESP power consumption. Components which mostly affect the power consumptions are pumps and motors. With this understanding, technology selection of ESP has been carefully determined to obtain significant result in power efficiency. Permanent Magnet Motor (PMM) is one of the ESP technologies that offers higher efficiency, higher power factor, greater power density and wider operating speed compared to conventional induction motor (IM). Short term field trial PMM ESP application has been conducted. Field-testing procedures and measurements on power consumption are presented both for PMM and existing IM at identical condition (head generated, motor rating, pump type & fluid rate). It yielded conclusive result that PMM has higher power efficiency. Thus, a wider application is justified and expected to have substantial energy savings and cost reductions. Currently, PMM is utilized at 20% of ESP wells in KS field. Field observation of these PMM-ESP units revealed power efficiency improvements by as much as 10-30% compared to IM ESP units. This improvement has led to the reduction of fuel gas consumption, which we have estimated to potentially save the company almost $ 750,000 per year in power generation expenditure. In the future, all IM ESP are planned to be replaced by PMM to gain higher cost reduction.
Kaji Semoga is an oil field located in Rimau block, South Sumatra, and currently being operated by Medco E&P Indonesia (MEPI). This field consists of three main reservoirs, namely Telisa sandstone (TLS), Baturaja limestone (BRF), and Talangakar sandstone Formation (TAF). The production from this field is mainly from BRF, which is a carbonate formation. In 1998, MEPI started to develop TLS, which is a laminated sandstone and shale reservoir at a depth of approximately 2000 to 3000 ft TVD. It has approximately 10 to 20% porosity with ranging permeability of 5 to 50 md. Telisa sandstone cannot be produced commercially without stimulation. Hydraulic fracturing is applied to increase productivity from this reservoir. Since 2002, almost 100 TLS wells have been fractured in stimulation campaign, with continuous improvement in technology and cost efficiency. The successful development of TLS with hydraulic fracturing led to further milestones to maximize oil recovery to deal with current oil price downturn. After a study with suitable samples and cases, the pillar fracturing technique was considered as a solution to increase the success ratio of hydraulic fracturing and increase the production through construction of infinite fracture conductivity. This method is similar to conventional proppant fracturing techniques where fluid and proppant are used to create conductive paths in the formation layer. However, pillar fracturing relies on open-flow channels. The proppant pillars that support the open-flow channels are created by pulsed delivery, engineered design, and innovative use of degradable fibers. With channels inside the fracture, fluid and polymer residue flow back faster than on conventional proppant fracturing, thus improving cleanup and increasing effective fracture half-length. In addition, pillar fracturing reduces the risk of screenout with the use of fibers that make fluid become more stable, while the presence of clean pulses around proppant structures promotes bridging-free flow. This paper provides a journey of the first two applications of the pillar fracturing technique in TLS, starting from candidate selection and continuing through pillar fracturing assessment and design, execution, and post-job evaluation. The technique is then compared to conventional hydraulic fracturing by reviewing initial production results from surrounding wells. Furthermore, this paper will cover how pillar fracturing could overcome conventional fracturing challenges such as early screenout, breaking to water zone, rapid production decline, and uneconomic production rate after fracturing. Two pilot wells have been safely executed with the pillar fracturing technique and the post-fracturing transient oil productivity index was superior, higher than nearby conventional fracturing wells. Another good result includes a significantly lower initial water cut in two pilot wells compared with water cut from adjacent wells. These outstanding results open the possibility for further application of the pillar fracturing technique to existing offset wells and for future production enhancement strategy.
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