Intelligent completion reaches the dawn of its second decade
Kirby Schrader, WellDynamics Inc.
This year marks the 10th anniversary of intelligent well completions, closing out a decade that began with a single North Sea installation and ended with 500 installations worldwide; five-year reliability expectations that grew from 70% to over 95%; and capabilities that expanded from simple zone shut-off to a range of sophisticated fluid control solutions.
As impressive as those landmarks may be, the technology’s second decade presents market challenges that demand new capabilities, stretching R&D efforts beyond today’s limits. At the heart of these challenges is an increased focus on ultimate recovery, with a goal of leaving as little hydrocarbon behind as possible. Many operators have targeted ultimate recovery goals of 70% or more – a lofty objective that has driven a renewed interest in the “digital oilfield,” or “smart field” technology. The challenges of field-wide management require addressing both workflow and team structures as well as technology.
In addition, maturing technologies from the 1990s and the early years of this decade are converging and integrating, providing well construction options that open a range of potential new solutions for multi-lateral, thin oil rim, and open-hole wells. Reliability, a major driver in intelligent completion technology’s first decade, has been adequately achieved – but concerns over risks associated with safely running intelligent completions and mitigating risks in all environments have re-focused R&D efforts on a range of new intelligent well solutions built on cableless technologies, as well as on all-electric integrated solutions first attempted in the 1990s.
The digital oilfield
Closely linked to increasing ultimate recovery is the digital oilfield, which aspires to manage an entire asset to deliver accelerated production, reduced downtime, increased efficiency, reduced drilling costs, and, ultimately, to maximize hydrocarbon recovery.
ERC wells are intelligent multi-lateral wells that do not require individual control lines from the wellhead to each lateral or zone, theoretically allowing an unlimited number of intelligent laterals – laterals segmented into multiple sections with independent sensing and flow control in each section.
The digital oilfield integrates real-time data acquired from downhole and surface sensors with reservoir and well models, and uses the resulting knowledge of the reservoir performance in conjunction with downhole flow control devices to optimize the asset using a process that includes the following:
- Modeling the asset using first-principles reservoir and well models, together with historical production data
- Measuring key downhole and surface parameters to generate a stream of data for input into these models to refine and improve the predictive accuracy of the models
- Optimizing asset performance by allowing engineers to run the model and change intelligent completion settings based on model results and on experience.
Achieving the goals of the digital oilfield will require operators to integrate operating philosophies, appropriate technologies, communications infrastructures, workflows, and team structures. It remains to be seen how quickly the promise of the digital oilfield is actualized.
Cableless technology
As distributed monitoring and control technology come of age, operators are seeking ways to remove dependency on umbilicals in order to achieve “extreme reservoir contact” (ERC) wells. ERC wells are intelligent multi-lateral wells that do not require individual control lines from the wellhead to each lateral or zone, theoretically allowing an unlimited number of intelligent laterals – laterals segmented into multiple sections with independent sensing and flow control in each section.
Making ERC wells a reality depends on cableless technology, which means a telemetry system coupled to a subsurface control module to control flow and data in each “smart” lateral, to exchange data, and commands with the main bore, and, ultimately to the surface. By taking advantage of field-proven intelligent completion technology for basic monitoring and flow control functions within the laterals, and working in collaboration with major oil and gas operators, the technology providers can reduce the technical risk and speed development of these systems.
Technology for unconventional applications
The convergence and integration of systems and processes developed during the 1990s and in the early years of this decade have provided a foundation for new technologies for unconventional applications such as tight gas, steam-assisted gravity drainage and steamfloods, and arctic and desert extreme environments.
Tight gas
The economic exploitation of tight gas has been challenging because it resides in three locations that are hard to develop: low-permeability sandstones and carbonates, gas shale, and coalbeds. New intelligent well technology may hold the key to unlock these vast reserves.
Remotely-operated hydraulic “frac” valves now can provide selective control of high-rate stimulation of multiple intervals in horizontal wells, and can improve operation time through the elimination of coil tubing trips. “Frac” valves may be cemented in place and can also be used after fracturing for simple selective production test and clean-up operations, with the ability to manipulate the valves later to shut off water or gas encroachment.
SAGD and steamfloods
Steam-assisted gravity drainage (SAGD) and steamflood recovery methods are used to produce high-viscosity hydrocarbon fluids that normally are too viscous to move through reservoir rock. Heating the hydrocarbon by injecting steam reduces fluid viscosity, making it easier for the oil to flow, and horizontal wells increase the reservoir contact to multiply well productivity. The economics of these processes depend on the efficient distribution of steam to evenly heat the hydrocarbon, and the ability to shut off steam once it breaks through from injection well to production well.
Current methods strive to distribute steam injection uniformly along the wellbore using a perforated liner and/or dual completion. To shut off steam break-through, operators must shut off and cool the well before mechanical intervention to isolate and plug the offending section.
Intelligent well steam valves currently in development, on the other hand, are designed specifically for horizontal steam applications. Intelligent well technology will provide operators with the control to uniformly distribute steam along the lateral, identify steam break-through using fiber optic distributed temperature sensing (DTS), and shut off steam by selectively isolating the break-through zones in the steam injector or oil production lateral. These types of valves can control injection in as many as 10 intervals, provide open/close control, and withstand the high temperatures of a steam environment, up to 650º F (343° C), with appropriate seals, control fluids, metallurgy, and metal-to-metal seals.
HP/HT applications
As the application of intelligent completion technology has become more prevalent in deeper wells, new intelligent well equipment is being designed for environments characterized by high pressure and/or high temperature.
The next generation of interval control valves, can now withstand pressures of up to 15 kpsi, and up to 325º F (163° C). These valves, featuring metal-to-metal primary seals and high debris tolerant designs, can function in either fluid or gas services and high flow rates.
Feed through packers have been tested up to 15 kpsi and 400º F (204° C), for applications in heavy brines such as ZnBr2, CaBr2, or Cesium Formate.
Feed-forward monitoring
As we have seen, intelligent completion technology has made active reservoir control a reality. As field integration and automation mature, we can expect the rise of a new generation of reservoir sensors which provide not just monitoring but also prediction capabilities.
Today, most sensors can detect a change in downhole conditions, such as a fluctuation in pressure or temperature, after that change has occurred. Operators use this information to adjust intelligent well equipment once they have received it, essentially using a “feed-back” control philosophy.
The immediate future promises technologies that will deliver “feed-forward control” to optimize reservoir responses that may occur many months in the future. Permanently installed well sensors such as electromagnetic, seismic, or gravity, will be able to identify changes in the reservoir before they occur at the wellbore, and automated analysis and control systems will recommend and implement setpoint adjustments to the controllable parameters.
Of course, feed-forward control represents a significant change in operating philosophy for intelligent wells that will demand a tradeoff between production optimization today and ultimate recovery tomorrow. The digital oilfield may deliver on how these decisions can best be made.
Ultimately, the evolution of intelligent completion technology in its second decade will be determined by an integration of new technology with new functionalities, new applications, and new market demands. What remains to be seen is how the industry brings these diverse directions together, and how the technologies to support these demand are developed and commercialized.
