Extended-reach and multilateral horizontal drill- ing techniques significantly increase wellbore/ reservoir contact. This augmented contact allows operators to use less drawdown pressure to achieve production rates equal to those of conventional vertical or deviated wells. The ability to optimize results from these standard configurations through better reservoir fluids management has been greatly enhanced by the development of remotely operated inflow control valves and chokes. These devices enable engineers to adjust flow from indi- vidual zones that are over- or underpressured or from those producing water or gas that may be det- rimental to overall well productivity. Long sections drilled horizontally through a


single reservoir, however, present a different set of challenges. In homogeneous formations, sig- nificant pressure drops occur within the open- hole interval as fluids flow from TD toward the heel of the well. The result may be significantly higher drawdown pressures at the heel than at the toe. Known as the heel-toe effect, this differ- ential causes unequal inflow along the well path and leads to water or gas coning at the heel (previous page). A possible consequence of this condition is an early end to the well’s productive life and substantial reserves left unrecovered in the lower section of the well. Water or gas breakthrough anywhere along the


length of the wellbore can also result from reser- voir heterogeneity or from differences in distances between the wellbore and fluid contacts. Pressure variations within the reservoir caused by reservoir compartmentalization or by interference from production- and injection-well flow can also lead to early breakthrough.1


Carbonate reservoirs,


because they tend to have a high degree of fractur- ing and permeability variation, are especially vul- nerable to uneven inflow profiles and accelerated water and gas breakthroughs.2 Many completions designed for long-reach


wells include sand control systems. If these com- pletions do not have isolation devices such as packers, annular flow can lead to severe erosion and plugging of sand screens. In the past such annular flow effects were countered with gravel packs or expandable sand screens. But gravel packs often reduce near-wellbore productivity. Expandable sand screens require complex instal- lation procedures and are prone to collapse later in the well’s life. In traditional completions the solution to an


increase in water or gas cut is to reduce the choke setting at the wellhead. This lowers draw- down pressure, resulting in lower production


Nozzle-Type ICD


Helical-Channel ICD


> Leading ICD types. Fluid from the formation (red arrows) flows through multiple screen layers mounted on an inner jacket, and along the annulus between the solid basepipe and the screens. It then enters the production tubing through a restriction in the case of nozzle- and orifice-based tools (top), or through a tortuous pathway in the case of helical- and tube-based devices (bottom).


rates but higher cumulative oil recovery. However, this simple solution generally does not work in wells drilled at high angles. In wells completed with “intelligent” technol-


ogy, operators may shut off or reduce flow from offending zones using remotely actuated down- hole valves. But horizontal wells designed to opti- mize reservoir exposure are often poor candidates for such strategies. Extremely long wells often have many zones. The limit on the number of wellhead penetrations available may render it impossible to deploy enough downhole control valves to be effective.3


Additionally, such comple-


tions are expensive, complex and fraught with risk when installed in long, high-angle sections. As a consequence, operators often choose to


produce these multiple-zone wells using isolating devices such as swellable packers. To mitigate crossflow and to promote uniform flow through the reservoir, they have turned to passive inflow control devices (ICDs) in combination with swellable pack- ers. By restraining, or normalizing, flow through high-rate sections, ICDs create higher drawdown pressures and thus higher flow rates along the bore- hole sections that are more resistant to flow. This corrects uneven flow caused by the heel-toe effect and heterogeneous permeability. Whether intended for injection or production, ICDs have applications in horizontal and devi-


ated wells and in several types of reservoirs.4 These devices are usually part of openhole com- pletions that also include sand screens. In addi- tion, ICD completions often use packers to segment the wellbore at points of large permea- bility contrast. This strategy combats water con- ing or gas cresting through fractured zones, halts annular flow between compartments and allows for isolation of potential wet zones. ICDs are also effective in reservoirs where


their ability to regulate inflow rates creates a suf- ficient pressure drop at the toe of the wellbore for the reservoir fluid to flow or lift filtercake and other solids to the surface. This article describes various ICD designs


OSWIN09/10—Rick, story #2—Figure 03


and how they are modeled to suit particular applications. Case histories from Asia, the North Sea and the Middle East illustrate how these pas- sive devices enable operators to increase well life and ultimate recovery.


Velocity Control Inflow control devices are included in the hard- ware placed at the formation/borehole interface. They use a variety of flow-through configurations including nozzles, tubes and labyrinth helical channels (above). These devices are intended to balance the well’s inflow profile and minimize annular flow at the cost of a limited, additional


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