Abstract

In offshore oilfield development projects using subsea tiebacks, severe riser slugging is of great concern, particularly for flowlines with downward slope at the riser base. In a recent conceptual design for a deepwater field, the flowline system consisted of a downward pipeline about 2,100m long and a steel catenary riser in 700-m deep water. Transient flow analysis indicated that severe riser slugging would occur. The paper describes the analysis of several mitigation techniques - increasing well lift-gas injection rate, injecting lift-gas at riser base and reducing riser diameter.

The study revealed that these severe slug mitigation techniques reduced the slug volume and frequency with different efficiencies. For the particular case study, increasing the lift gas at wellbore bottom of 1 MMSCFD from the base case of 3 MMSCFD was the most efficient technique to eliminate severe slugging. Riser base gas lift required 3 MMSCFD in addition to the 3 MMSCFD lift gas at the bottom of wellbore. Mitigation by reducing riser diameter was not effective because it required a 2" reduction in the diameter and would make flowline pigging difficult. The analysis also showed that including the wellbore in transient flow models for the short-distance flowlines is essential. Without the wellbore model, no severe riser slugging was predicted.

Introduction

Subsea tieback has been increasingly used in the development of deepwater oil and gas fields. In a typical subsea production system, produced fluids flow through a wellbore, a subsea flowline and a riser. Flow patterns in the production flowlines and risers may be in stratified flow, slug flow, or annular flow. A flow regime of particular concern and may cause the most damage to topsides equipment is the severe riser slugging. Severe riser slugging occurs when liquid accumulates at the riser base and totally fill a section of the flowline and riser for an extended period of time under some flow conditions, especially when there is a downward slope in the flowline at the riser base and the flowrate is low. During this period of time, gas accumulates behind the liquid section and its pressure increases. When the pressure is high enough, the liquid columns is blown out of the riser at high velocity and as a long slug. The slug will impose large impact forces on the elbows, chokes and closed valves in the riser system, and also may flood the topside separators.

To avoid the large pressure surge and the liquid flowrate surge in severe slugging, production strategy should be optimized so that the operations are outside the slugging producing regions. The flow stability and the remediation methods should be studied for each subsea development.

This paper describes a case study for a subsea manifolded production system in which severe slugging will occur in the late life of the field development. The slug mitigation techniques investigated were increasing gas-lift rate, reducing riser diameter, injecting gas at the riser base in addition to the wellbore gas lift, and choking at topside before separator.

System description

The reservoir is produced by three production wells. Figure 1 shows the development concept. Dual flowlines are used to tie back a subsea manifold to a FPSO. The two proposed flowline diameters are 6-inch ID, each with a 6-inch ID catenary riser, determined by the maximum flowrates for these wells. The dual flowlines design is used to facilitate testing and pigging operations. One well production flows in the first line and two-well production flows in the other flowline. The following section introduces the production pipeline and the riser profile, the fluid property and the production data.

Flowline and riser profiles

A FPSO is located at 700-m deep water and the wellhead is 2500 m away from the FPSO in 600-m deep water. A typical well has a MD of 4307 m and TVD of 2784 m.

The gas injection point is 2907 m MD. The well tubing is 5.5" (4.892"ID).

Figure 2 shows the pipeline and riser profiles.