Your fellow subsea engineer finally returns from honeymoon dive trip, all tan and rested, talking incessantly about how great it was, etc. etc. While everyone is getting back up to speed on the subsea equipment delivery status, drilling results and recent developments, you spent all week and the weekend churning through subsea development options and issues for these new oil reservoirs discovered in your project’s development well pre-drilling. And your company reservoir engineers and geologists are all saying its looking more and more like they will have the best well trajectory and reservoir penetration by drilling these new reservoirs from a surface location about 3 miles to the southwest of where your wells are located (just confirming – these are directionally drilled from 3 miles away?).

Fluid sample data is not yet available (sent from rig to the lab), but unofficially you were told they looked like they were contaminated with drilling mud. No water samples were taken, no cores either. One of the oil zones looked very clean, but it was unclear how big the reservoir was at the location where it would be penetrated. Given the preliminary geologic mapping, there was some debate as the whether there was an oil water contact seen on the log.

Question 1: What are the important system level flow assurance issues that need to be assessed, if these new reservoirs are going to be drilled 3 miles away from the tie-in point to the existing gas system?

Question 2: In the architecture, will the oil be tied-in to the existing gas system? If so, what flow assurance issues can arise due to the fluids mixing?