Comprehensive field development design for a tight gas chalk-reservoir in north sea: A capstone design project

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.