It is a sobering statistic that 68 of 76 proposed major offshore developments were cancelled in 2015. There has been gradual improvement since then with system cost reductions and the oil price recovery, but nonetheless prospects that could be very profitable with the right development concept have been rendered uneconomic by overblown cost estimates. Conversely prospects with poor economics may go ahead due to overestimated production expectations.

Production forecasts are generated by reservoir models. These models are often first constructed early in the development process, and refined multiple times as the process progresses and more information becomes available, e.g., from appraisal wells and production history. Meantime, production system design and sizing are often performed by different groups in the E&P company or by subcontractors in virtual isolation from each other. Updates from the reservoir modelling are not necessarily shared between these groups resulting in disconnects that can impact project viability and economics.

Better collaboration between these groups and use of integrated reservoir and production system models address and sometimes resolve these issues. However, even in cases where integrated models are used, rather than harnessing the full power of the reservoir model, it is often dumbed down. This is done primarily in an attempt to save time, but it results in poorer representation of the actual reservoir response, e.g. losing the effect of well interference and failing to capture the pressure distribution and pressure changes with time in the reservoir.

In this paper some real examples are provided of disconnects and lack of modelling fidelity with the potential for severe consequences on project economic performance. The four examples that will be discussed in this paper are as follows:

• Over-simplification of the reservoir representation for a gas field led to a proposed high-capacity subsea compression system being uneconomical. Reevaluating with a full reservoir model showed the compression system was over-sized and would underperform. Correcting these issues transformed the project economics and enabled the project to progress towards the FID.
• A simplified representation of the reservoir for a tieback resulted in insufficient natural production (no artificial lift) to be economic and insufficient production increase to justify subsea pumping. However, when reevaluated with more detail, the project became economical using a pumping concept.
• Passing a simplified production forecast from the reservoir team to the flow assurance team for a long tieback development resulted in overlooking the most onerous period of production for thermal management. If this oversight had made its way into the final design of flowline insulation, the tieback may well have plugged with wax deposits within a few years of operation. Use of complete forecasts within an integrated simulation framework prevents this kind of issue.
• Use of an inappropriate simplifying assumption while evaluating a brownfield redevelopment resulted in an overestimated production potential of the proposed new wells. When the error was corrected, an additional iteration of the development concept to downsize it was required which delayed first oil. Integrated reservoir and production system modelling avoid these kinds of planning and investment mistakes happening in the first place.

This paper challenges the notion that detailed, integrated simulation is not required until later stages (FEED, execution) of a field development project, if at all. The presented examples are based on actual project experience. They provide quantitative evidence that integrated simulations have avoided costly development concept iterations and even more costly mistakes. Sometimes this allowed assets with marginal economics to be reconsidered for the operators’ project execution pipeline. Sometimes it resulted in the need to revisit economic analysis and development concepts due to initial overestimation of well performance.