Completion engineers are controlling production without leaving the office.

Talked to your reservoir lately? Using satellites and fiber-optic cables to communicate with multiple pay zones, Petrobras' Well Automation Group (WAG) has set its sights on truly intelligent completions. And it won't be long before the remaining downhole tools required to harmonize production are developed.
In the old days, the equation was pretty simple: One reservoir meant one completion meant one well. That changed with the advent of dual completions, which allowed a single wellbore to receive production from two reservoirs. Although dual completions could reduce well numbers by half, reserves were not exploited effectively, and well numbers remained unnecessarily high. Combining completions to commingle production from multiple pay zones reduced well numbers and costs, but two drawbacks emerged. First, well intervention was required more often than not. Second, heterogeneous reservoirs were treated as if they were identical.
The ideal is to treat pay zones individually as this makes for a much deeper understanding of reservoir characteristics. Consequently, this leads to better reservoir management, which in turn means higher levels of production over a longer life span. This was the overwhelming logic behind single and dual completions. But large numbers of wells do not make the best use of resources.
So two questions surfaced: Could pay zones be completed together but still be treated separately to optimize production? And could this be done using remote control or an intelligent completion system?
Forming a joint venture to find out, Shell, Agip, Statoil (Saga Petroleum), BP Exploration and TotalFinaElf used technology from Petroleum Energy Services on the first-ever intelligent completion installation 5 years ago. The successful test proved the approach was valid and paved the way for further testing. Twenty wells have been intelligently completed worldwide.
Although reservoirs are complicated, intelligent completions are simple. Essentially, they take a big-picture view and aim to cost-effectively manage heterogeneous pay zones. Production from interrelated or layered reservoirs must be continually regulated and commingled. And real-time data must be provided to make the best management decisions regarding the use of a network of downhole chokes, gauges and fiber optics to regulate production.
Synergy is the real value of completing wells intelligently as numerous pay zones are produced in unison. It is widely recognized that depleting one reservoir affects another nearby. By regulating the flow and pressure of several reservoirs, a balance can be achieved, ensuring reservoirs behave according to what is best in light of the big picture. Zonal isolation is a good example of how intelligent completions can help predict, isolate and balance water and gas influxes in different locations according to long-term needs. Another benefit is that gas and water can be injected into multilateral or multilayer reservoir zones with a better understanding of how this will affect production from interconnected reservoirs.
By manipulating a downhole network of chokes and gauges, a production engineer seated hundreds of miles away can manage the production of several reservoirs, wells and fields. In this way safety is improved, costs are cut, and more reserves are accessed.
Broadly speaking, high-cost developments such as subsea installations with high intervention costs are particularly well suited to intelligent completion. Their greater depths and complex well trajectories also make them ideal candidates. Two other areas suited to intelligent completion are selective production of multiple reservoirs and optimizing artificial lift operations.
With intelligent completion still in its infancy, financial costs are high and investment can be justified only on high-return projects. Technical restrictions exist also. Usage is limited to wellbore diameters of 7 in. or larger, with high flow rates, typically 6,000 bbl or greater. Downhole temperatures cannot exceed 247°F (120°C).
Despite these limitations and relatively few worldwide installations, major oil companies are devoting more resources to completing wells intelligently.
System approach
WAG has been instrumental in identifying technology and supplier gaps and bringing service companies together to fill them. Although its long-term focus is on deepwater scenarios in the Campos and Santos basins, Petrobras chose Varg 7, an onshore well in Mossoro, Rio Grande Do Norte, to test the system. Along with much lower levels of operating cost and risk, the onshore location also offered greater ease of installation and test recording. In this initial test, the major objective was to avoid interventions and optimize injection into two different areas. Besides supplying the reservoir engineer - in Natal, 292 miles (470 km) from the wellhead - with such essential data concerning reservoir characteristics as pressure and flow rate, the system also allowed these characteristics to be controlled and changed.
WAG team members reasoned that if the network - designed with a proprietary fail-to-safety element - went down, production would not be affected. One of the first trials used Baker Oil Tools' electronic wireline system comprising a single electric cable with two pairs of wire, enabling it to descend in any wet Christmas tree prepared to receive a crystal gauge. As depicted, the intelligent completion is made up of six further elements that serve as either connection or flow mechanisms.
A 20-ft (6-m) intelligent expansion joint ensures the electrical circuit is completed. The joint descends into a designated opening and after completing its job is retrieved using wireline. The joint was developed specifically for Petrobras and is part of the only intelligent completion system that does not rely on the packer and the riser.
The disconnection joint allows the top part of the production column to be disconnected. Incorporating a vertical orienting mechanism (a standard upper joint fits into a lower receiving connection), the joint ensures proper electrical connection is maintained. Endowed with a soft landing feature, the electronic connector reconnects the system at a speed of 1 ft/sec, allowing for a heave of 0.5 ft/sec without the use of a compensator.
The ICS Packer (95/8 in. by 51/2 in.) is set hydraulically, incorporates bidirectional slips and can carry five 1/4-in. lines. Running a deactivation tool on "flexitube" deflates the packer.
Reservoir flow is measured by the flow measurement unit (FMU), a 51/2-in. monophase gauge. Based on a venturi design, it can be adjusted to flow measurement. The venturi is run and replaced using wireline or flexitube. When zonal flows change, it is possible to substitute the venturi for a new and more accurate flow measurement and smaller pressure loss. In the case of this application, the flow gauge measures the total flow. A similar 31/2-in. venturi gauge measures flows inside the 7-in. casing.
The intelligent production regulator (IPR) is a 51/2-in. variable choke (the design is based on a sliding sleeve principle) that can be set in an infinite number of positions. Providing an open flow area, the choke also measures pressure and temperature in either the column or the annular space. Based on pressure and temperature data obtained from the open flow area, flow rates can be calculated quickly and accurately. Closing the choke completely enables a formation test to be conducted, and the buildup or fallout can be visualized and registered directly.
The shrouded intelligent production regulator is an infinitely variable 31/2-in. choke encased by 7-in. casing. It monitors and regulates the flow arising from the lower reservoir zone. It was specially manufactured because neither chokes nor flow gauges were capable of fulfilling this function.
Petrobras' first installation - the 17th intelligent completion worldwide - was the first to use a disconnection and expansion joint as well as remote data monitoring and satellite control. Recent developments in fiber optics enabled their transfer to the oil industry.
These low-cost hydraulic-based systems, capable of withstanding temperatures up to 481°F (250° C), can be used in 51/2-in. wellbores with low flow rates. Another major advantage associated with fiber optics is the absence of electronic downhole devices to measure temperature, pressure and flow. This makes viable applications that previously were impossible due to high temperatures.
Permanently monitored wells and reservoirs based on fiber optics are still in their infancy. Conventional systems typically are electronic but can be used in an array of permanent and temporary well monitoring applications. However, the reliability of electronic compounds is reduced in high-temperature environments.
Not surprisingly, sensor durability and reliability are the main criteria for control and instrumentation selection. This has driven the development of fiber-optic sensor technology, and despite a limited track record, the technology seems to withstand harsh downhole conditions. Compact and light fiber-optic sensors also are explosion-proof and immune to electromagnetic interference. Compared with electronic sensors, fiber-optic technology can operate in much higher temperatures and higher pressures, allowing multichannel communication systems.
Truly intelligent completion systems are some way off. Perhaps a more accurate description of today's technology would be remote control completions, as completions are not yet closed-loop. In other words, they are not autonomous, self-controlling systems. Human input is still required. However, with technology moving at an inexorable pace, closed-loop completions will be operating downhole within this decade.
Representing unquestionably better production, automation is an irreversible process. Each downhole sensor that sends real-time data makes us more conscious of its value. As more subsea equipment is integrated within the intelligent completion, it becomes more difficult to view reservoirs separately. And automation offers an unprecedented flexibility in terms of asset and production management strategy. As commodity prices fluctuate, production from a given field can be halted or accelerated to mirror market conditions.
Editor's note: Jose Luiz Arias Vidal of Petrobras' WAG supplied technical information for this article.

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