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.
The world industrial revolution has entered industry 4.0, where cyber-physical systems monitor physical processes over the internet of things (IoT) and cloud computing. SCADA is one of area where the industry 4.0 can be implemented, which could swift the way of work to monitor and control wells production from human dependent to real time data dependent. However, the implementation of SCADA technology is usually constrained by expensive cost. In the KS brownfield, ESP is the major artificial lift. Most of the ESP are controlled with variable speed drive (VSD) without being connected to online monitoring system. To check the ESP status and healthy pump condition, it requires extensive manpower for daily site visit. By using supervisory control and data acquisition, the ESP status and parameters can be transferred directly to the users. The GSM-cellular network in the KS field covers most the wells location. This network can be an option to optimize the initial cost impact in SCADA implementation. A single platform of SCADA with automatic notification and well modeling capability in web-based application is also prepared to provide clear analysis based on real-time ESP parameters and widely accessible. Simple GSM modem installed inside the VSD box to transfer critical parameters on real-time basis through the internet. During the implementation, some issues especially related to modem communication device aroused which significantly gave negative impact in this project. To handle these issues, more schematic communication and modem modification then implemented to withstand certain unexpected condition. Automatic machine notification and intelligent alarm are also create great benefit to increase operator response time. This paper will describe why this type of SCADA system is a fit to purpose solution for this typical brownfield with simple installation, relatively low cost, good communication performance and decent security.
The development of oil and gas fields in recent years has become more technically and economically challenging. Interdisciplinary interaction is needed to have effective and efficient field planning. Indeed, it has been noted that field management by using integrated surface-subsurface modeling will have an extremely positive effect on production. This paper presents the interdisciplinary teamwork between subsurface and surface engineering in their efforts to construct an integrated production model for Kaji Semoga field, a large and complex onshore production field located in South Sumatra, Indonesia. The model covers about 180 wells, which are spread over 45 clusters, and surface facilities in three field processing stations. It covers all facilities from well up to the nearest field station for separating gas from oil and for compressing it prior to distributing to clusters and finally injecting the well. The model also incorporates 84 new ESP, which will be installed by the end of year 2009 to replace the existing gas lift system. The model predicts an additional oil gain of 2,500 bopd (14.7%) as a result of installing ESP. About 170,000 blpd of liquid will be produced after the ESP installation project is completed. Consequently, liquid handling in each station has become a critical issue to be resolved before all the ESPs are installed. Several operational manoeuvers have been carried out to handle the forthcoming produced liquid by utilizing the model. About 300 bopd (1.8%) of oil gain from the cluster flow diversion scenario has already been realized. Apart from the liquid handling issue, the model also highlights the future gas-lift gas requirement for the remaining gas lift wells. Several active compressors can be shut down as a result of the outcome of the model, so the operating cost can be reduced significantly. The model also identifies potential bottlenecks along the production trunkline, which can result in a potential reduction of 140 bopd. In addition, the model also identifies a potential oil gain of about 220 bopd (1.3%) if back pressure on several production trunklines can be minimized. Field engineers have benefitted from the use of this model: it can help them assess any changes or manoeuvres in the field. This is expected to add about 200 bopd (1.2%). Some of these changes and manoeuvres are being executed this year.
As one of gas field producers located in South Sumatra Indonesia, the S field produced 70 MMSCFD as its peak production. It is a high pressure and high temperature gas impurities of 30% CO2 and 100-ppm H2S. The field has been producing since April 2010, with current recovery more than 50% of initial gas in place. Utilizing initial estimated OGIP (Original Gas In Place), the gas deliverability was predicted to last only until 2022. There are high uncertainties in estimating accurate reserves value due to lack of reservoir data such as reservoir pressure and SCAL (Special Core Analysis). Therefore, additional information such as SBHP (Static Bottom Hole Pressure) survey data and well optimization are essential to be conducted to narrow the uncertainties in reserves estimation and gas deliverability. Apparently, in 2018 and 2019 during CPP (Central Processing Plant) shut down for preventive maintenance activity, SBHP survey could be performed. Additional pressure data was utilized to update the OGIP analysis by combining several methods such as p/z analysis, flowing material balance, rate transient analysis and history matching of dynamic model analysis. The analysis shows conclusive result that there is significant increase in the OGIP and reserves, estimated 16% of additional gas reserves. To support enhance gas deliverability, the production network model was then created to evaluate existing production method. This updated system analysis showed significant bottleneck at the existing production system that limiting the production rate from the wells. As part of debottlenecking endeavor, temperature survey on the production system was employed to overcome the limited availability of pressure survey points in the system. Furthermore, the successful debottlenecking activity combined with temperature drop analysis resulted in 20% additional gas deliverability. This integrated evaluation and optimization also prolong the field lifetime until 2025. This paper describes some of the challenges and lessons learned during the evaluation and optimization in the high pressure and high temperature sour gas field.
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