Intelligent completion technology (i.e., a system capable of remotely activate preinstalled downhole tools without direct well intervention) took its first R&D steps in the mid-1990s in a joint industrial project aimed at developing the first commercial intelligent completion system. Since then, the technology has evolved, becoming very widespread and much more reliable.

Eni ran the first intelligent completions in the Mediterranean Sea on the deepwater Aquila project with mixed results. The company’s most recent experience with intelligent completions in West Africa, however, has met with success. The project was the industry’s first execution of a three-level frac pack intelligent completion, and the technology offered the full textbook suite of benefits: accelerated production, increased recoverable reserves, and fewer development wells.

West Africa first
Eni faced three significant challenges in planning the ABO 11development well on the deepwater ABO field offshore Nigeria: the three productive zones had to be selectively isolated and monitored (per Nigerian policy), commingled flow from layers with different oil and reservoir characteristics had to be managed, and sand control management was required to prevent sand production. An additional reservoir management goal was to accelerate production of the deeper layers and achieve a production increase.

The intelligent completion increased cumulative production from ABO 1. The base case (purple), two (red) zones and three (yellow) zones used intelligent completion. (Images courtesy of Eni)

Eni carried out feasibility and risk analysis during the planning phase, leading to selection of the intelligent completion with frac pack as the best solution. Several benefits justified the increased cost of this technology: overall project capital expenditure (capex) reduction (one well versus three), increase in expected cumulative production, and anticipated production of the reservoir’s lower layers.

The well came onstream in February 2009, with overall project capex reduced by 35% and cumulative production increased by 20%.

Business case for intelligent completions
The project base case initially envisaged one well for each of the two main producing zones. This assumption was forced by the impossibility of running a dual completion due to tight clearance between tubing hanger and casing and the need to avoid workover during the well’s life. Comparing capex for the base and intelligent completion cases showed that with intelligent completion on three layers, drilling could be limited to a single phase. Drilling capex could be reduced by 70% compared to the base case, while completion capex could be reduced by up to 45% of the original approval for expenditure. A simplification of the subsea production systems allowed further enhancement to the project economics.

Design issues, challenges
The upper completion for ABO 11 included two 2-in. flow control valves with seven positions, one 3 1/2-in. flow control valve with 10 positions, two seal unit multiports with hydraulic and electrical feed-throughs, one production packer with six feed-throughs, and a downhole monitoring system. The completion was designed to incorporate a frac pack sand control assembly.

The selected production casing had a 9 5/8-in. OD. To install the frac pack assembly and flow control valves inside the screens, it was decided to run 7-in. wire wrapped screens, 23 lb/ft, but with 2-in. reduced size control valves that had to be re-engineered from the conventional 3.5-in. size.

Like other fields offshore Nigeria, ABO is characterized by sand with high permeability. A frac pack was preferred to a gravel pack for sand management based on experience on ABO main. The first design was confirmed during the drilling phase, and a 20/40 mesh was selected. A major constraint was to achieve a good result in frac pack operation with the 7-in. wire wrapped screens installed within the production casing with a clearance of less than 1 in., as recommended in the best practice of frac pack operations.

Sand control
The selected brine for the two upper zones was 1.23 specific gravity (SG) CaCl. For the third zone only, it was increased to 1.25 SG. A tubing-conveyed perforating (TCP) assembly with 7-in. guns with big-hole 12 shots per foot was the perforating selected. After perforations, losses were controlled by fluid and by pumping a viscosified solids-free pill to avoid damage to the formation.With the screens assembly in hole, an acid pill was pumped before each frac operation.

The details of the frac pack zone are illustrated

No nonproductive time (NPT) was recorded during TCP operations. Some NPT resulted from electronic connection malfunctions and weather during fracing and pumping. The use of a stimulation vessel, initially not planned, eventually resulted in nearly five days’ delay. TCP runs (running in hole and pull-out), screens and lower completion runs in hole, and frac pack operations (makeup flowhead, stub-in, and pumping) were considered an entire operation package for each zone.

Frac pack operations were carried out for each zone, with the lower zone proving to be the best because a clear screen-out was achieved with subsequent stress and re-stress to achieve the best perforation cover. The complete slurry volume was pumped into the formation for each level. The middle and upper zones were fractured and pumped without a clear screen-out to avoid formation damage. Each lower completion assembly was made up with a flapper isolation valve to prevent damage from debris falling into the formation and screens.

Completion operations
The downhole monitoring system was designed to monitor pressure, temperature, and the functioning of the flow-control valves. Three annulus gauges monitor reservoir pressure. The lower and middle gauges are part of the upper completion string located inside the production casing as tubing-retrievable inside a single gauge mandrel. Single gauges were exposed and oriented to the flowing annulus to monitor pressure and temperature before drawdown inside the flow-control valve. It is possible to close each valve and monitor reservoir buildup without shutting down the well.

When running in hole, the last valve was open while two valves remained closed. Avoiding the dummy run also was an advantage because with this kind of multiport and valves, the risk of damage with respect to a correctly performed space-out was higher because the lower completion was exposed to potential damage.

Lessons learned
Two years were spent reviewing the details of the project and adopting the learnings from two previous experiences on ABO 9 and 10 (two zone intelligent completions with sand control). In the end, there were a number of significant lessons learned:

The tight clearance of the completion is shown.

-Early involvement of the reservoir and completion departments is ideal;

-Materials and electrical continuity must be performed on a dry mate connector and electrical splice, as provided by vendors, before running the completion;

-Subsea motherboard cards must be supplied in advance by the subsea vendor so site integration tests and load coefficients can be communicated to downhole permanent gauges;

-The contingency plan must be discussed with the completion supplier in case a failure happens during the running in-hole phase. For ABO 11, Eni ran a perforation contingency system just below each valve that makes it possible to orient perforations in case of valve failure in the closed position (this kind of valve will not move if the control line is sheared);

-Slickline operations must be drastically reduced to avoid flat time in subsea applications and to eliminate invasive operations that could damage intelligent completion functionality; and

-A dedicated team is the best approach for a challenging project of this kind. The ABO 11 installation is considered a success, today producing 11,000 b/d of oil.