A Combined Well Completion and Flow Dynamic Modeling for a Dual-Lateral Well Load-up Investigation
Authors: Tang Yula , Huang W.S. Bill 
Published: February 2016

A dual-lateral well was completed in a Chevron subsea condensate field with high peak rate. Within one year, the production significantly declined with high water-cut. The well was shut down and then brought back to production, observing much reduced flow rate for three days and eventually stopped flow.

During the production depletion, shuts-in, restarts and finally stop flowing periods, the gas well experienced liquid load-up involving unstable operation conditions and changing reservoir deliverability. The conventional steady-state based liquid load-up prediction approach and nodal analysis are insufficient to answer what happens when the well shuts in, restarts and eventually dies. To address the intrinsically transient multi-phase flow problems, a combined study of completion inflow analysis and wellbore dynamic simulation was performed.

The analysis indicates that the well's productivity had been substantially reduced. Before shut-in, the surface pipeline system induced unstable production conditions due to the low flow rates. After shut-in, the wellbore fluids underwent phase redistribution and liquid was loaded up in the lower wellbore/laterals. Wellhead gas-lift or changing to smaller tubing would not revive the well. Lack of gas supply was the main reason for the well's inability to flow. Analysis shows that, if a coiled-tubing gas-lift operation is feasible, the well could be put back online with an average liquid flow rate of 8,000 stb/d. Gas-lift duration and allowable shut-in time were evaluated to consider the liquid removal and clean-up effect.

The lesson learned is that, shut-in is an irreversible process that causes gas-liquid redistribution in the wellbore. The very important operating principle for this kind of well conditions is not to shut-in the well to avoid unnecessary intervention. A combined study of completion inflow analysis and wellbore dynamic simulation provides a unique approach for solving liquid load-up and for providing mitigation measurements.

Background

A Chevron subsea field was drilled with a dual-lateral well using the Weatherford Starburst system. The dual-lateral completion schematic is shown in Figure 1. It produces gas and condensate from the S-reservoir, and oil with associated gas from the B-reservoir along a 16km flow line to the central platform for processing.

Typically the well produced at a FWHP of 54 bars to a separator approximately 165 m from the seabed at 20 bars. The peak production rates were 77 MMscf/d and 6,300 stbo/d in Oct., 2004. The production declined to 16 MMscf/d and 900 stbo/d with WC of 70% a year later. TABLE 1 shows some selected, representative production history indicating the production trend of oil and gas fast decline and water cut increase.

After a shut down in Dec., 2005, the well came on-line at a reduced rate of about 4 MMscf/d and 800 bbl/d of liquid, and over a period of 3 days it stopped producing. It seems that this well has become liquid loaded and was unable to get back production even with reduced separator pressure. The production history and field observation shows that the dynamic instability conditions exist before the well's being killed.

Liquid Load-up: Static vs. Dynamic Stability.

Liquid loading is a common production problem with depleted condensate gas reservoir. Liquid (condensate or water) accumulates in the wellbore could severely reduce production and eventually cause the well to die. A critical velocity exists when gas can no longer transport liquid upwards through the well tubing. Turner et al.'s entrained spherical liquid droplet model1 for critical gas velocity is a widely accepted approach to determine the minimum required gas production rate to maintain production. Many modifications and application discussion2–5 have been published.

When liquid loads up in the gas well, the tubing performance may become unstable. The conventional nodal analysis can tell if the system is stable or not by judging the intersection points of IPR and TPC (Tubing Performance Curve)4, 6. As shown in Figure 2 by Lea and Nickens4, the intersection point around A and B is unstable (on the left) and the intersection point around C and D is stable (on the right). This approach is called static instability analysis as the TPC is based on steady-state multi-phase flow correlations.