Automated Well Control Increases Performance Of Mature Gas-Lifted Fields, Sendji Case

Abstract

Abstract This paper reviews one recent example of benefits of the implementation of a full control of wells tool offshore Guinea Gulf. This field case confirms the full control of wells smart automation increases by 10% the daily oil production of a mature field. It also confirms production increase above 20% under sensitive situations. Using measurements and adjustments only at well head avoids work over and ensures robustness. Setting parameters related to physics such as ranking or starting lift gas tunes the standard sequences to any well and topsides. Other fields applications include dual gas lift and dynamic control of gas coning to maximize recovery. Upgrading the well control to digital allows a remote operation. High quality data improves understanding the behavior of mature wells. Beyond this supervision, two levels of control algorithm provide with a continuous and autonomous control of the unmanned platforms. This smart control monitors and automates both single well and platform levels to handle transient phases and to face unforeseen behavior of reservoir, wells and facilities. Automated sequences help the operators if any trouble on a well or topsides. Remote manual operation cannot account continuously and accordingly for many wells particularly during hurried restart phases. This smart control increases the uptime and efficiency of wells and topsides. It stabilizes at source the compression and topsides intake. It also increases the recovery factor. Introduction The Sendji offshore field has been started-up in 1983 offshore Congo: see figure 1 field location and major data. The average water cut of this mature field was above 60% in 1999. 54 out of the 55 oil producer wells are gas lifted. These wells are located in 4 unmanned platforms plus one platform close to the central one. Fluids are transferred to the central platform under multiphase flow. Oil is produced from 12 heterogeneous Albian reservoirs with sandstone or lime. Operation difficulties are increased by sharp differences between the wells. Some of them are unconsolidated which require specific operational procedures to prevent formation damage. Water drive activity depends on the reservoir causing long transient phenomena during the restart phase. Oil viscosity changes from 4 to above 60 cPo under the reservoir conditions. Some reservoir induces wax and thick emulsion problems. The major driving force to consider an upgrade of the well control with an automation was a poor uptime. Due to old installation and difficult operating conditions, shut down of wells and facilities were frequent during day and night. Improving the well control was motivated by other consequences of the surges coming from the wells. They were causing temporary overload due to a limited capacity of water treatment. The surges also disturb the export line which is common with other fields. A control upgrading could improve the touchy well operation due to sand production, emulsion and wax. Different start-up and restart procedures according to each well were difficult to fully apply by all the shifts sometimes confused by the almost unpredictable behavior of some wells. The OPEX increase due to the production decline was a concern. The 5 platforms make the operation heavy. Upgrading the well control to digital allows a remote operation. High quality data improves understanding the behavior of mature wells. However, limiting digital control to remote operation requires the full hardware and has limits when operating mature fields. An efficient dynamic control of a whole field is not practical. A well control upgrading has been considered with a smart automation using the full control of wells. These control algorithms were already widely field proven over almost 10 years in the TFE group. The expected benefits were an oil increase of about 1000 bopd and remote soft well restarts with validated procedures. The project has excluded 7 wells with a too poor production potential.