Digital oilfield

First Three-Zone Intelligent Completion in Brazilian Presalt: Challenges and Lessons

Since the first intelligent completion was installed 20 years ago, the systems have become increasingly complex in order to reach productivity and optimization goals, allowing real-time independent monitoring and management of each zone in the well.


Since the first intelligent completion was installed 20 years ago, the systems have become increasingly complex in order to reach productivity and optimization goals, allowing real-time independent monitoring and management of each zone in the well. Accompanying the search for greater system efficiency is the goal of reliability assurance. This paper presents the complexity and challenges of planning and installing the first intelligent completion in a subsea well with three producing zones in the Brazilian presalt.


Below water depths greater than 7,200 ft, below salt layers up to 6,500 ft thick, and at true vertical depths (TVDs) of approximately 18,000 ft lie the presalt fields. The distance from shore (as much as 300 km), high carbon dioxide and hydrogen sulfide concentrations, high temperatures (sometimes greater than 100°C), and the existence of multiple intervals with different porosities all add to the challenges of producing from the presalt successfully.

Through the installation of permanent downhole gauges (PDGs), intelligent completion allows real-time monitoring of downhole parameters such as pressure and temperature, providing a better understanding of what is happening at any given time. Hydraulically actuated flow-control valves give the operators the ability to access each interval with the touch of a button, greatly improving reaction time and reducing the need for costly interventions. Furthermore, valves with adjustable choke settings increase ultimate recovery from the reservoir by fine tuning the production/injection of each individual zone. Chemicals can be injected to ensure productivity and avoid potential problems to production such as scale and asphaltene buildup.

Equipment Design and Configuration

Flat-pack (FP) and control-line protectors (clamps) were designed to ensure maximum flexibility, allowing for wells to be completed with one, two, or three zones without the need for additional equipment.

The splice subs also were designed with flexibility in mind. The lower the splice sub is positioned, the fewer the slots that are necessary. However, by supplying all of the subs with the same number of slots, the same slot sizes, and the same slot positioning, the equipment could be used in any type of well layout and inventory management was greatly improved.

The design of the pressure and temperature gauges and their carriers was also optimized. Instead of the PDG dictating whether the data are acquired from the tubing or the annulus, the mandrels do that. This was made possible by having two different configurations for the area where the gauge is mounted to the carrier. The tubing mandrel has a through hole allowing fluid from the inside of the string to contact the gauge’s inlet port, while the annulus mandrel has a blank interface with cross-shaped slots through which annulus fluids enter the sensor’s inlet.

Prejob Preparation

Preparation to perform the offshore installation began when confirmation of the completion layout was received. The well in question would be completed in the Santos presalt area, approximately 240 km offshore Rio de Janeiro and in a water depth of 7,218 ft. The well would tap into three producing intervals between 16,161- and 16,601-ft TVD and later be tied back to a floating production, storage, and offloading vessel (FPSO).

A schematic of the intelligent-­completion subassemblies is shown in Fig. 1. Although very similar, the subassemblies did have some differences. Every zone had its own dual-annulus PDG, but the top zone was also fitted with a dual tubing gauge.

Fig. 1—Intelligent-completion subassemblies.


Chemical-injection mandrels (CIMs) were installed only in the lower zones, with annulus injection being used in the intermediate interval and tubing injection being used in the bottom interval. This was because of the number of penetrations available in the tubing hanger. Because each zone was fitted with an inflow-control valve (ICV) that required four hydraulic lines and the downhole safety valve (DHSV) required two lines, the two remaining penetrations allowed for only two CIMs.

The top splice sub and top feed-through packer had a higher minimum yield strength than the other subassemblies. The top packer also had an additional control-line penetration.

Before assembly could begin, a few points had to be evaluated. Given the number of control lines and ­tubing-encased conductors (TECs) necessary to operate the tools downhole, a study was conducted to identify where each line would be positioned, connected, and crossed. Equipment alignment was also checked before torquing the subassemblies, in order to ensure good routing of the control lines and avoid unnecessary crossing.

A system-integration test was conducted by connecting all three ICVs and PDGs to the top flat packs and the master control system (MCS) of the subsea supplier. The scope of work included demonstrating that the ICVs could be controlled by the MCS through a hydraulic-control-line architecture and that the PDGs could be monitored correctly by the MCS.

Offshore Installation

After the equipment was shipped to the rig and before running in hole (RIH), the team had numerous tasks to perform, including checking the flat packs and subassemblies for damage during transportation, installing each PDG to its subassembly and testing it, and finding a suitable location for the spoolers.

After all intelligent-completion subassemblies were installed to the string and the main flat packs were connected, production tubing was run. Control-line clamps were installed on every coupling, and an autoclamp was used to position the flat packs against the tubing so the clamps could be attached. The autoclamp functions as an articulated arm with rollers through which the flat packs are fed.

The installation continued with additional equipment being added to the string, including the nipple, the gas lift mandrel, and the DHSV. The tubing hanger (TH) was installed, and the TH-running tool, shearable riser joint, and umbilical assembly were connected to the TH. The control-line connections were made, and the TEC connection to the TH was tested. When all testing was finished, the control lines were pressured to check integrity while RIH and to avoid inadvertently cycling the ICVs.

The TH was run to depth and set in the production adapter base, and a wireline trip was performed to confirm the correct positioning of the packers. After testing the DHSV, the ICVs were closed to pressure the tubing and set the packers.

After closing the valves, the three packers were set simultaneously by pressuring the tubing against a plugged nipple located at the base of the string. The setting was observed by the pressure falloff provided by the annular PDG readings of each zone and confirmed through a 4,000-psi pressure test on the annulus above the top packer. The TH-running tool was brought back to surface, and the tree was installed. With the tree installed, each zone was individually stimulated by opening the ICV and injecting acid to remove damage while the formation’s behavior was monitored through the PDGs.

The well was later tied back to the FPSO, and the intelligent well-control system was installed and commissioned.


The installation of the first three-zone intelligent completion in the presalt area presented a great number of challenges (e.g., distance from shore, water depth, design complexity), but, through careful planning, attention to detail, and synergy between the service company and the operator, it was a great success. Because the equipment supplied for the well was to be used in several other wells with different configurations (e.g., two or three zones, injector or producer, with or without formation-isolation valve), a focus on flexibility was a priority during the design phase of the system components. By using global standard practices, procedures, and policies and customizing them to the project’s scenario, a fit-for-purpose solution was provided to meet the operator’s needs. The lessons learned from the issues encountered during offshore installation helped pave the way for numerous two- and three-zone intelligent completions in the presalt that followed, improving installation quality and efficiency.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 28136, “First Three-Zone Intelligent Completion in the Brazilian Presalt: Design Considerations, Challenges, and Lessons Learned,” by Filipe Del Vecchio, Potiani Maciel, Francisco Salom, José Chagas, and Antonio Ortiz, Baker Hughes, a GE Company, prepared for the 2017 Offshore Technology Conference Brasil, Rio de Janeiro, 24–26 October. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.