Production optimization of unstable wells maximises production rates

The aim of the well engineering study was to debottleneck flow restrictions of unstable production wells to maximize and maintain production rates.

The Challenge

The operator had tied-in a new satellite field to an existing production facility. Upon production start-up, it was identified that the production from the satellites showed significant instabilities with pressure and flow rate oscillations.

Some of the wells also ceased to flow after a period of unstable production and were subsequently shut down. This production environment caused huge challenges at the process facility topside and it was decided to kick off a debottlenecking project with the mandate of evaluating the cause of this behavior and propose mitigating options.

With an expected production in the excess of 50,000 bbls of oil per day from the satellites – it was crucial to solve this problem quickly and effectively.

What we did

Our flow assurance experts were contacted to assist the debottlenecking task force.

During this project, our engineers:

• Built a network model of the production system (the initial simulations aligned well with the actual production data taken from the online flow monitoring system)
• Conducted transient simulations
• Identified solutions to maximize and maintain production rates

The findings

Initially, it was believed the unstable production was caused by water entrainment from the reservoir, however, we demonstrated that this in fact, was not the case, through transient simulations.

Through these simulations, it was identified:

• That the wells experienced slug flow due to low gas velocities and consequently liquid accumulation in the tubulars
• The pressure behind the liquid plug containing mostly oil and condensate (with a very small amount of water) built until it was sufficient to blow the liquid slug to the seabed
• This oscillating behaviour continued until some of the wells ceased to flow
• It was obvious that the completion size used for these wells were not optimized based on the reservoir and fluid conditions.

The short-term solution

Included installing a smaller sized tubing in the existing production wells. By doing this, the simulations showed that the production would stabilize, and for some of the wells, the flow rate would even increase.

The long-term solution

To include gas lift mandrels on new production wells. By doing so and using continuous gas injection, simulations showed not only stable production, but also, based on an optimized gas injection rate of 2 mmscf/d, the production would exceed the rate initially planned for.