A total system production optimization model has been implemented in a complex gas-lifted offshore operation, resulting in production gains and operating cost reductions. Whereas previous optimization models considered only the wells and production gathering network, the new model is able to consider the combined performance of the total system, including downhole well configurations, the complex production gathering and lift-gas distribution pipeline networks, separators, compressors and pumps. The model is applicable to most gas-lifted fields, and will be particularly beneficial when applied to those with complex production systems, and where compressors are a constraint on total system performance. The output from the optimization model principally comprises recommended values for individual well gas lift injection rates, separator pressures, compressor discharge pressures and compressor utilization. Field results are presented in the paper to demonstrate how implementing the optimizer's recommendations in the field resulted in economic benefits through increased production and reduced operating costs. Also described is how the model allows field operations engineers to re-optimize field control parameters on a more frequent basis and with less manpower than previously. The successful implementation of a complex model with such a broad scope is as dependent upon the implementation process as it is upon the technology. Therefore, in addition to describing the details of the model itself, this paper will cover the issues that arose during the implementation and how they were resolved. These include the level of manpower and support required, project organization and execution, and the processes required to sustain the benefits after the initial optimization gains have been realized. Introduction Dubai Petroleum Company (DPC) has implemented a production optimization tool that has yielded production gains and operating cost reductions. The field optimization software is used to model the complex production networks associated with the gas-lifted fields, including the downhole well configurations and the surface facility components such as gas compressor trains, pipelines and surface pumps. Key benefits realized from all fields were a 3% total production increase, a 4% reduction in lift gas requirements and a 3% reduction in operating costs. Field operations support was critical to the project's success by continuously tracking the operational parameters throughout implementation to validate the recommendations and results. The project was planned to be executed in three phases, including a pilot study, to assess the value of a full field model and to identify and resolve implementation challenges. The full field model was implemented during 2003 and produced several key learnings about the level of manpower and support required, the importance of accurate well model tuning, and the value that a detailed compressor model can add to a system highly dependent on compressor efficiency. Challenges associated with the gas lift control systems, which are nearing obsolescence, were also identified and created a need for alternative strategies depending on the length of time that the gas lift rate reallocation would be in effect. The full field optimization process utilizes an integrated approach to address operational challenges. A team of engineers and operations personnel now proactively manages events based on a well-defined strategy. The optimization model has allowed gas lift reallocations to be performed on a more frequent basis with less manpower. Based on these reallocations, production increases have been realized and the fields are currently operating at the historically lowest separator pressures. Offline studies have been performed to recommend process equipment modifications and justify major equipment overhauls. The integrated network model has also been used as a predictive tool to forecast the impact of ambient conditions and scheduled maintenance on production rates. The results are currently being monitored to determine the value of adding a fully automated interface to the system model software package.

This paper describes the development of an integrated production network model for a major producing field located in the Western Offshore Region of India, the second most prolific oil field in India. The purpose is threefold:presentation of a case history describing successful implementation of optimisation methodology in a major gas lifted field,outlining the structure and methodology for constructing and calibrating a large integrated production model, andillustrating the potential applications in running the completed model in optimisation mode. The Heera Field, currently producing from 119 strings (all on gas lift except one) has been on production since 1984 and with recovery in the region of 20% considerable potential still exists for improving production and recovery. One of the areas and challenges for improvement involves the optimisation of the gas lift performance. The Heera network model described in this paper includes the multi-phase well production, gas lift injection, production processing and gas lift compression facilities that comprise the asset. The development of the network model comprised the following elements:Well models were constructed for all the producing strings using nodal analysis. Outflow performance was calibrated to existing flowing gradient survey (FGS) data and recent production test data.Fluid properties were characterized based on Black Oil correlations using four independent PVT datasets, and tuned to a single correlation across the entire field.Approximately 450 independent pipe/flowline objects were included in the model to represent major pipelines, risers and downcomers.Three major processing platforms, comprising 5 HP separators, MP and LP separators, and 5 gas lift compressors operating in parallel were modelled.Production from neighbouring complexes (Neelam and ICP) was included in the form of "object sources" with overall delivery point at the Uran terminal located onshore. The network model was built, history matched and calibrated to actual field data, within a tolerance of <1% for the measured liquids production. The calibrated model was then used to run a number of optimisation scenarios, in an effort to find ways of improving production and operating efficiency. Optimisation investigations conducted within the framework of this project indicate potential oil uplift of between 6–8% from a combination of well interventions (based on individual well modelling and gas lift diagnostics) and network optimisation (lift gas reallocation), as well as a reduction in total lift gas requirement and compressor horsepower. Besides the scope for production gains and operational improvements, the project also highlights a number of higher level issues relevant to the development and employment of integrated production network models:The successful implementation of the Heera network model is the first of its kind in ONGC's India operations.The technology utilised in this project is capable of modelling large scale complex production networks in a robust and reliable manner. Complexity and size need no longer be barriers to successful implementation of network modelling and optimisation.The technology is easily transferable for implementation by production engineering and operations staff in the field, provided standardised workflows are identified and new work practices implemented to allow improved data management and model maintenance.The maintained integrated production network model provides a platform for analysing and diagnosing a wide variety of production and equipment related issues in the field.

Summary A total-system production-optimization model has been implemented in a complex gas lifted offshore operation, resulting in production gains and operating-cost reductions. Whereas previous optimization models considered only the wells and production-gathering network, the new model is able to consider the combined performance of the total system, including downhole well configurations, the complex production-gathering and lift-gas-distribution pipeline networks, separators, compressors, and pumps. The model is applicable to most gas lifted fields and will be particularly beneficial when applied to those with complex production systems, and those where compressors are a constraint on total-system performance. The output from the optimization model principally comprises recommended values for individual-well gas lift injection rates, separator pressures, compressor discharge pressures, and compressor use. Field results are presented in this paper to demonstrate how implementing the optimizer's recommendations in the field resulted in economic benefits through increased production and reduced operating costs. Also described is how the model allows field operations engineers to reoptimize field control parameters on a more frequent basis and with less manpower than previously. The successful implementation of a complex model with such a broad scope is as dependent on the implementation process as it is on the technology. Therefore, in addition to describing the details of the model itself, this paper will cover the issues that arose during the implementation and how they were resolved. These include the level of manpower and support required, project organization and execution, and the processes required to sustain the benefits after the initial optimization gains have been realized. Introduction Dubai Petroleum Company (DPC) has implemented a production-optimization tool that has yielded production gains and operating-cost reductions. The field-otpimization software is used to model the complex production networks associated with the gas lifted fields, including the downhole well configurations and the surface-facility components such as gas-compressor trains, pipelines, and surface pumps. Key benefits realized from all fields were a 3% total production increase, a 4% reduction in lift-gas requirements, and a 3% reduction in operating costs. Field operations support was critical to the project's success by tracking the operational parameters continuously throughout implementation to validate the recommendations and results. The project was planned to be executed in three phases, including a pilot study to assess the value of a full-field model and to identify and resolve implementation challenges. The full-field model was implemented during 2003 and produced several key learnings about the level of manpower and support required, the importance of accurate well-model tuning, and the value that a detailed compressor model can add to a system highly dependent on compressor efficiency. Challenges associated with the gas lift control systems, which are nearing obsolescence, were also identified and created a need for alternative strategies depending on the length of time that the gas lift rate reallocation would be in effect. The full-field optimization process uses an integrated approach to address operational challenges. A team of engineers and operations personnel now manages events proactively on the basis of a well-defined strategy. The optimization model has allowed gas lift reallocations to be performed on a more frequent basis and with less manpower. On the basis of these reallocations, production increases have been realized and the fields are currently operating at the historically lowest separator pressures. Offline studies have been performed to recommend process-equipment modifications and justify major equipment overhauls. The integrated network model has also been used as a predictive tool to forecast the impact of ambient conditions and scheduled maintenance on production rates. The results are being monitored currently to determine the value of adding a fully automated interface to the system-model software package.

The Falah field offshore Dubai consists of four satellite platforms and is mostly produced by gas lift. High pressure lift gas is received from the main SWFateh field and the produced fluid and gas after a two-phase separation are returned to SWFateh through long sub-sea pipelines. The system is constrained both on the gas lift supply and surface production networks. The conversion of two of the major gas lift producers to electric submersible pump (ESP) has helped de-bottleneck the Falah system. The main objectives were to increase drawdown in these wells using ESP and to reduce the load on the gas lift and production systems. Both of these objectives have been successfully achieved. This paper will describe the system constraints, the options considered and the economics associated with each option. The modeling work that helped the justification for the ESP installation will also be described. The selection of well candidates was an important criterion for success. From a reservoir perspective the goal was to achieve improved oil recovery with increased drawdown. From a facility perspective the wells were selected at the farthest (FB) platform that had the minimum gas lift pressure in the field. Commissioning of the ESPs has reduced the gas load on the system and the production system pressures have decreased as a result. Gas lift operating depths would be deepened in some of the Falah wells, taking advantage of the increased gas lift header pressure now available. The use of ESP for de-bottlenecking a gas lifted field is an excellent example of production system optimization. This demonstrates how a different type of artificial lift can be effectively used to improve the productivity of a field that uses one type of artificial lift.