Bouchard graduated with a degree in Economics in 1980 and started training as a wireline logging engineer in 1981. In the late 1990s he cofounded a company focused on multilateral well junctions. He joined Reslink in 2004, representing the company in North and South America. Reslink, a supplier of robust wire-wrapped sand screens for sandface completions and inflow control devices (ICDs), was acquired by Schlumberger in December 2006. Presently based in Calgary, Michel is currently focused on applying ICD technology to heavy oil.

 A great number of heavy oil wells rely on horizontal completions and are thus prone to the flow control challenges inherent to this type of completion such as the “heel-to-toe” effect from friction loss along the wellbore, as well as pressure, fluid mobility and permeability contrasts in the producing section. There is a natural tendency to have much higher production at the heel (near the vertical part of well) than the toe (at the end of the well). In the presence of a gas cap or water table, water or gas coning is likely to occur much sooner near the heel, greatly impairing overall well production. Where water and/or gas are creating drive, or steam is being injected, breakthrough will lead to loss of pressure, resulting in a loss of reserves and making intervention necessary.

Variable permeability, reservoir pressure and fluid mobility along the well can cause a similar effect. Flow will be greater in sections with high permeability, rendering them more prone to coning, pressure reduction, and, ultimately causing issues for production stability. Addressing the challenges related to irregular flow is the basis for developing ICDs, most of which are deployed in long horizontal wells.

Steam-assisted gravity drainage (SAGD) wells present among the greatest flow control challenges of all heavy oil applications. The SAGD process usually involves the drilling from a single vertical bore of two parallel horizontal wells, one on top of each other. The upper well is dedicated to steam injection and the bottom one to production. The heel-to-toe effect will normally result in greater injectivity (upper well) and productivity (bottom well) at the heel. Combined with the fact that the heels are directly on top of each other and sometime as close as 5 meters apart, this situation is very likely to lead to premature steam breakthrough. This is one of the most undesirable events in a SAGD operation as it effectively shuts down production.  The problem can be exacerbated by variable injection temperature, because steam temperature is likely to be higher at the heel than at the toe.

Typically, 75% of the total cost of SAGD operations is related to generating steam, so there is an enormous upside to minimizing cumulative steam-oil ratio (CSOR). One way to improve the CSOR is to ensure an even distribution of the steam chamber along the entire horizontal wellbore. The introduction of ICDs in both the injector and producer can help equalize the injection and production flow along both wellbores, reducing the risk of premature steam breakthrough and/or water production from formations beneath the oil producer. Another substantial benefit of inflow control is the increased recovery coming from parts of the well closer to the toe and from lower permeability streaks, which might otherwise not be contributing. The overall end result is improved recovery at reduced cost.

The low cost of slotted liners has made them, to date, the completion of choice for SAGD wells. Many operators consider that the relatively shallow depth and short horizontal section of most SAGD wells does not justify the higher cost associated with stronger and more accurate sand control screens such as those offered by Reslink.  Higher quality screens provide better sand control, higher mechanical strength and longer life, but many SAGD operators have so far been reluctant to make the additional capital investment, which can be more than three times as much as slotted liners. However, the improved recovery enabled by ICDs can make longer horizontal sections more economical and justify the benefits of better screens. Furthermore, the CSOR and recovery improvements attributable to ICDs can easily recover the incremental cost of higher quality screens—possibly within months—and decrease the risk of a premature steam breakthrough or coning. Better sand control also provides additional savings by reducing wear, and thus extending the life of downhole equipment such as electric submersible pumps (ESPs) and upper equipment.

Some benefit can be gained through varying the density of slots in the slotted liner—less slots at the heel, and more at the toe. However, this crude system has generally been found to be inadequate for regulating flow. It is not as effective as ICDs at equalizing the reservoir inflow along the entire length of the wellbore.

ResInject

Schlumberger combines its Resflow* ICDs with wire-wrap sand screens to create a production management system that intelligently integrates sand control and flow control in a versatile, simple and robust solution. Screens are wrapped on unperforated base pipe. Each screen joint is equipped with a ResFlow ICD housing. Fluids enter the screen, and flow between the screen jacket and base pipe into the ICD housing and through ceramic nozzles into the screen base pipe. A pressure drop is achieved across the nozzles. This pressure drop, based on the Bernoulli principle, is independent of fluid viscosity, and so no adjustments are required when water cut (or GOR) increases. The “sister” tool—the ResInject* device—does the opposite in injection wells; distributing injection fluids along the entire well section. Injection and production systems have slightly different configurations: to avoid erosion, the nozzles in an injection control device are placed in a ring around the base pipe directing the fluid flow longitudinally to the base pipe. 

Schlumberger has built considerable experience using the ResFlow system in conventional oil production and water injection wells and is currently performing an extensive research program to evaluate nozzle performance with steam. This includes theoretical fluid dynamic simulations and testing, using production information from several operators who are interested in the potential of the technology for heavy oil applications.

ICDs are being incorporated into the ECLIPSE thermal simulation tool to model the effects of adding ICDs into a reservoir over time. The NETool simulator is used to compute multiphase fluid inflow and outflow between the wellbore and the reservoir. This enables a quick qualitative “snapshot” of how the reservoir will behave with and without ICDs in a variety of scenarios. It can also be coupled with ECLIPSE software to extend the predictions over time.

Schlumberger is also investigating how to configure the ICD nozzles to provide the most efficient warm-up and circulation for SAGD operations. For the first few months of a SAGD operation, steam is circulated at relatively low volumes, typically 50 m³/day, to heat the formation. Once the heavy oil or bitumen becomes less viscous, steam circulation progresses to become steam injection, and as the steam chamber expands, the amount of steam is gradually increased to rates around 1,000 m³/day after about 1 year. Dynamic control systems are being developed to enable the ICDs to effectively manage these variable flow rates. Engineering activities are also ongoing for optimizing ICD nozzle injection configurations for vapor extraction (VAPEX), a non-thermal recovery method that involves injecting vaporized solvents.