Automation and data-driven models have been proven to yield commercial success in several oil fields worldwide with reported technical advantages related to improved reservoir management. This paper demonstrates the implementation of an integrated workflow to enhance CO2 injection project performance in a giant onshore smart oil field in Abu Dhabi. Since commissioning, proactive evaluation of the reservoir management strategy is enabled via smart-exception-based surveillance routines that facilitate reservoir/pattern/well performance review and supporting the decision making process. Prolonging the production sustainability of each well is a key pillar of this work, which has been made more quantifiable using live-tracking of the produced CO2 content and corrosion indicators. The intensive computing technical tasks and data aggregation from different sources; such as well testing and real time production/injection measurements; are integrated in an automatic workflow in a single platform. Accordingly, real-time visualizations and dashboards are also generated automatically; to orchestrate information, models and multidisciplinary knowledge in a systematic and efficient manner; allowing engineers to focus on problematic wells and giving attention to opportunity generation in a timely manner. Complemented with numerical techniques and other decision support tools, the intelligent system data-driven model assist to obtain a reliable short-term forecast in a shorter time and help making quick decisions on day-to-day operational optimization aspects. These dashboards have allowed measuring the true well/pattern performance towards operational objectives and production targets. A complete set of KPI's has helped to identify well health-status, potential risks and thus mitigate them for short/long term recovery to obtain an optimum reservoir energy balance in daily bases. In case of unexpected well performance behaviors, the dashboards have provided data insights on the root causes of different well issues and thus remedial actions were proposed accordingly. Maintaining CO2 miscibility is also ensured by having the right pressure support around producers, taking proactive actions from continues evaluation of producer-injector connectivity/interdependency, improving injection/production schedule, validating/tuning streamline model based on surveillance insights, avoiding CO2 recycling, optimizing data acquisition plan with potential cost saving while taking preventive measures to minimize well/facility corrosion impact. In this work, best reservoir management practices have been implemented to create a value of 12% incremental oil recovery from the field. The applied methodology uses an integrated automation and data-driven modeling approach to tackle CO2 injection project management challenges in real-time.
The petroleum industry is faced with a number of enormous challenges resulting from the declining oil prices such as high abandonment and new wells construction costs, low sweep efficiency, harsh environments etc. These challenges can be met by designing a long term field development plan of a petroleum prospect, ensuring maximum recovery without sacrificing the safety standards. This work describes a multicomponent and strategic development plan designed for a tight gas reservoir, starting from formation evaluation to drilling-completion and economic analysis in addition to the environmental issues that must be considered in advance. The authors also acknowledge the support of: The field is principally a gas condensate field, where the reservoir is mainly Chalk with an average porosity of 27% and average permeability of 0.1mD with 65% water saturation. The reservoir pressure (5960 psia) and dew point (5940 psia) being very close, the reservoir is close to saturation pressure and gas condensate is expected to form immediately on commencing production. PVT studies indicated that the critical condensate saturation will not be reached which in turn means that it will never be mobile or recoverable with reservoir pressure decline. Given the fact that the water drive is rather weak, pressure maintenance methods will be needed to avoid the condensation of gas within the reservoir. Based on petro-physical evaluation, our team was able to construct a static reservoir model using Petrel Software and the team suggested three different development scenarios consisting of horizontal and multilateral wells of various configurations. Based on the development strategies, a dynamic model is constructed for each scenario to compare the techno-economic feasibility and selection of the most optimum strategy. It was found that the field would be economically viable to produce for a time period of 50 years and the simulation results indicate that an ultimate recovery of 69-76% was achieved if water injection is applied from year-1 onwards. Moreover, the highest recovery factor of 76% is achieved with scenario-B as it has a five spot pattern with 8 vertical injection and 3 multilateral production wells. In addition, the most delayed water breakthrough is achieved in this scenario that occurs after 2.5 years. Moreover, it was also observed that the pressure maintenance was 100% effective in scenario-C as the reservoir pressure increased as a result of increasing the water injection rate rather than increasing the sweep efficiency. However, for the other scenarios, the reservoir pressure drops but not below the critical value. Finally, a cumulative gas production of 389-424 MMMSCF was observed along with a gas production rate of 8.61-24.7MMSCF/day giving a cumulative net present value of $890,000 with a payback period of 5 years, indicating that the project is economically viable after 50 years.
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