Production Operations: Inflow-Control Devices

Abstract

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 108700, "Inflow-Control Devices: Application and Value Quantification of a Developing Technology," by F.T. Al-Khelaiwi, SPE, and D.R. Davies, SPE, Heriot-Watt U., prepared for the 2007 SPE International Oil Conference and Exhibition in Mexico, Veracruz, Mexico, 27–30 June. The paper has not been peer reviewed. Horizontal and multilateral completions are a proven, superior development option in many reservoir situations. However, they are susceptible to coning toward the heel of the well despite their maximizing of reservoir contact. This is a result of frictional pressure drop and/or permeability variations along the well. Annular flow, leading to severe erosion and screen plugging, is another challenge. Inflow-control devices (ICDs) were proposed as a solution to these difficulties in the early 1990s. ICDs have gained popularity recently and are being applied to a wider range of field types. Their ability to control the well inflow profile has been confirmed by a variety of field monitoring techniques. Introduction ICDs are a new sandface completion technology specifically developed to help balance the inflow contribution along horizontal wellbores. Extensive flow-loop testing and subsequent field experience have proved the potential of ICDs to extend well life by extending the plateau period, minimizing water and gas coning, minimizing annular flow, and increasing recovery. Historical Development Norsk Hydro introduced the ICD technology in the early 1990s to enhance the performance of horizontal wells in the Troll field, a giant gas field on the Norwegian shelf of the North Sea. The field contains a thin oil column (4 to 27 m thick) overlain by a large gas cap and underlain by an aquifer. The field was developed originally as a gas field in the "thin-oil-column" part of the field because the production of such a thin oil column was deemed nonviable with conventional wells. Two horizontal wells then were drilled, and long-term well tests were conducted to determine the ability of such wells to drain the oil economically. The wells were completed with large-diameter prepacked slotted liners to reduce the effect of frictional pressure losses along the wellbores. The long-term-test results indicated that a significant oil-production potential existed. The initial flow rate of the first well was four times that expected from a vertical well. The well productivity index was very high, at approximately 6000 std m3/d/bar, which is 5 to 10 times higher than that expected from a vertical well. This also meant that a small pressure drop of only 0.5 to 1.0 bar is sufficient drawdown pressure to produce the well at a target rate of 3000 to 5000 std m3/d. A new field-development plan was put in place that used horizontal wells. However, production logging of the first test well indicated that 75% of the contribution was coming from the first half of the horizontal section. This is indicative of the significant effect frictional pressure losses can have on the performance of horizontal wells once this frictional pressure drop is of the order of magnitude of the drawdown.