Situational concerns drive development of well-by-well engineered solutions, but the reward is worth the effort.

Today we have the capability to place wellbores exactly where we want them, accessing multiple reservoirs, each with its own set of characteristics. The principles of process control and methodologies of production optimization provide the tools for understanding and exploiting many of the new 'situational' challenges.

Focusing on downhole issues, the initial completions must be driven by designs that: (1) fulfill development deliverability criteria, and; (2) accommodate reasonable, risked uncertainties associated with the reservoir response to depletion. At issue are "Simplicity-for-Availability" versus "Complexity-for-Flexibility", and the sensitivity of the resulting completion philosophy to the cost (and risk) of an unplanned intervention.

Commingled completions

Downhole production optimization issues focus on improving the ability to selectively and remotely monitor and control multiple intervals. Owing to the incremental cost associated with the required downhole and surface equipment, the candidates fall into two categories:

• Those in which the incremental value of remote monitoring and control within the projected well life can easily justify the added expense, and
• Those in which the value justification is questionable.

Fortunately, technology exists to address both situations. Even in marginal conditions economically justifiable commingled completions can be achieved (Figure 1).

While the justification process is well understood in principle, each operator has its own criteria, biases and opinions, and this process is always performed based on individual well/asset criteria. The service industry has also developed significant expertise and specialized tools to aid in the justification process.
Downhole power and communications architectures

Implementation of permanent sensors and downhole flow control requires the deployment of small diameter control lines. These lines connect the surface system with the individual sensing and actuator components downhole, forming the hydraulic, electrical, optical and/or hybrid physical architecture. These lines are routinely bundled in a flat-pack configuration comprised of the individual lines, surrounded by a molded polymeric encapsulation material compatible with downhole conditions. The finished flat-pack has a rectangular form, typically 0.4-in. (11 mm) thick and 1.4-in. (36mm) wide.

The individual control lines provide pressure- and mechanically-isolated pathways for the various unique power and communications channels inside. Great care is taken in properly buffering the individual electrical conductors and optical fibers with various filler materials to further protect them from long-term vibration and other effects while downhole.

The bulk encapsulating material serves to integrate multiple lines into a single manageable structure for spoolability and handling; to ensure separation of the lines from each other; and to provide abrasion and added crush resistance to the individual control lines during deployment and protection from erosion during well flowing operations.

So-called "bumper bars" may also be incorporated into the encapsulated flat-pack. Bumper bars are typically parallel, multi-strand lengths of wire rope of a larger diameter than the control lines. These too provide for added crush resistance over the full length of the flat-pack downhole. As the completion is deployed the flat-pack is paid-out from a tensioning spool through a specialized sheave assembly, and attached to the tubing utilizing over-coupling clamps.

The primary job of the clamps is to provide a level of controlled, radial standoff protection from the various stack and wellbore interior discontinuities. Additionally, they serve to distribute the hanging weight of the flat-pack along the tubing. It is noteworthy that historically, the most failure-prone components of in-well monitoring systems are connector terminations, either at downhole components or at the Christmas tree. Most suppliers have invested heavily in improvement of this technology, providing metal-to-metal sealing systems and facilities for external pressure testing of the assembled connector on the rig-floor after make-up. With the number of connections increasing in advanced completions, this will remain an area of continued focus in the future.

Feedthrough packer systems

Packers continue to evolve as the primary wellbore pressure barriers. Early adaptations of conventional dual-string casing packer designs served to accommodate feedthrough requirements of specialized electrical submersible pump (ESP) completions. Low-performance, sealing requirements of these systems was provided by a gland/nut, stuffing-box-type elastomeric seal that was compressed on the insulation layer of the ESP cable in a section where the armor was removed.

In 'gassier' ESP/Packer systems, an epoxy-potted penetrator is incorporated into the packer. The cable is cut at the packer position, and field-attachable connectors are molded onto the cable ends for attachment above and below the penetrator.

Today however, in the higher temperature/pressure environments of flowing oil and gas wells, intelligent monitoring and control systems require feedthrough sealing capabilities equal to, or greater than, the ratings of the production/isolation packers. Available in sizes ranging from 51/2 in. to 103/4 in., today's feedthrough packer systems provide testable, metal-to-metal sealing capabilities for up to 8 control lines.
Additionally, and consistent with conventional high pressure/high temperature applications, intelligent well system functionality downhole must accommodate extremes in tubing expansion/contraction. This is accomplished by specialized expansion joints with working stroke-lengths of up to
20 ft. (6 m) and control line bypasses for up to six control lines.

Permanent downhole instrumentation

Production optimization discussions typically revolve around the acquisition, handling, storage and interpretation of acquired sensory data. Bottomhole pressure measurements in the producing well arguably remain the most valuable piece of information for reservoir and production engineers. But it is expected that demand for downhole measurements will increase dramatically. In this sense, additional measurements will mean not only increased measurement frequency, but an increase in the measurement parameters needed (multi-phase flow, temperature, pressure, strain, resistivity, sand-detection, seismic, etc.); and measurement density (multi-point, distributed, continuous, etc.) (Figure 2).
Production optimization techniques will probably always be limited by either the number and type of available data points, or the data handling and interpretation capacity required to make use of them.

Remote downhole flow control

Fundamental process control principles for production optimization must include the ability to respond to changes in process conditions. Remotely actuated control valves located downhole complete the extension of process control. Primary among the current applications of downhole flow control valves are hydraulically actuated sliding sleeves and adjustable chokes. These devices are quite reliable and limited only by their control systems' susceptibility to control fluid leakage/contamination and inherent valve positioning limits at long distances without direct feedback control. Hybrid electro-hydraulic systems, manifold-type systems, and pressure-pulse type systems are also available for increased selective valve control. Electrically actuated sleeve-type control valves are also available, which have the inherent benefit of integrated power and direct feedback control. However, they have not as yet found a broad user-base in the industry, primarily due to their lack of field history.

Remotely controlled downhole control valves are being employed in an ever-growing range of applications. A short list of installations and uses follows:

• Selective, multi-zone commingled flow;
• Downhole water/gas shut-off;
• Injection well zonal rate allocation;
• Dump-flood control;
• Auto-gas lift;
• Drawdown distribution control;
• Selective secondary permeability adaptation in extended-reach horizontal wells;
• Lateral production control in multilateral;
• Zonal shut-off/control below ESPs.

Conclusion

The principles of production optimization don't change when the process is extended into the wellbore. However, the well design and completion must incorporate the architectural components to implement the process. This article has reviewed some of the basic concepts, tools and functionality involved in intelligent well systems to date.

More than 200 intelligent wells are in operation today throughout the world. With additional experience and continuing improvements based on the lessons learned, the true benefits of production enhancement and optimization will be realized by a growing operator base in the years to come.