Passive inflow-control devices (ICDs) are used to enhance the performance of horizontal producing wells in unfa- vorable environments such as non- uniform permeability and/or pressure variations along horizontal sections. ICDs were combined with a fiber-optic distributed-temperature-sensing (DTS) system to manage the water-injection profile across a reservoir horizon. This field trial demonstrated the effective- ness of the ICD system when used for injection-well profiling and for fluid diversion during acid stimulation. Introduction To understand the injection profile and well performance, a DTS system was deployed with ICDs and swellable packers as a field trial in a planned injection well. The objectives were to provide real-time information on multirate testing, determine real-time compartmental-injection profiling, and eliminate the need for horizontal flow- meter logging and well intervention. Recent designs use ICD-completion technology with a DTS umbilical deployed in the openhole producing section below a liner for real-time mon- itoring and controlling of inflow from each compartment, thereby extend- ing well life and increasing recovery. This case involved the use of DTS and ICD technology to control injec- tion profiles in an openhole near-hor- izontal well. Compartments were cre- ated by use of water-swellable packers with feedthrough capabilities for the DTS umbilical. Completion Design The reservoir section was separated into six compartments. On the basis of openhole-log analysis, the reservoir has a uniform porosity along the length of the well, with a few dolomite intervals present. The spacing of the ICDs and packers was planned in such a way as to isolate these dolomite sections while distributing the desired injection rate along the well. To mitigate the risk of getting stuck while running the lower completion to total depth, it was decid- ed to limit the number of openhole packers to six, thereby reducing the number of allowable compartments. DTS System and Installation The DTS and a permanent downhole- monitoring system were installed in April 2009. The fiber-optic DTS cable was attached and secured to the production- tubing string and provides multipoint temperature profiles across the length of the well. The real-time data from the DTS system can be used for injection optimization and reservoir management by monitoring injection rates between and within the ICD compartments and by identifying crossflow conditions. The DTS cable was deployed on the outside of a 4 1 / 2-in. tubing string above the production packer, which then was crossed over to a 3 1 / 2-in. stinger tail pipe to convey the DTS cable, ICDs, and swell packers to the desired setting depth inside the 6 1 / 8-in. openhole sec- tion of the well. After nippling up and testing the wellhead bonnet, the well was monitored for 3 1 / 2 hours during well displacement to diesel. This opera- tion allowed the geothermal temperature gradient of the well to be established. Reservoir Optimization The reservoir is a heterogeneous frac- tured carbonate with high structural relief. Historically, vertical power-water injectors were drilled at the periphery of the field to provide pressure support. Because these wells were at structurally low positions, 4 to 5 km down-dip from the first line of producers and close to the aquifer, they were less than efficient. Consequently, the line of injectors was moved up-dip on the structure as near- horizontal completions. This strategy introduced new challenges because the reservoir is highly fractured. Although the wells would have high injection rates, the injection profile would be fracture dominated causing premature water breakthrough at the producers, resulting in poor flood-front advance- ment and, in some cases, water above oil in the reservoir. The ICD technology was tested in an effort to distribute injection evenly through the length of the well to opti- mize sweep efficiency and delay water breakthrough. The injection well was drilled highly slanted, penetrating the entire reservoir. It was completed with ICDs and a DTS system for real-time monitoring of flow into each compart- ment. The planned injection rate for the well was 15,000 B/D. Injection Performance The well was placed on injection in August 2009 at an initial injection rate of 8,400 B/D. The initial injection-tem- perature profile showed a cold injection temperature all the way to the toe, indi- cating that injection water reached total depth. A quantitative analysis requires a warm-back survey. This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 127772, “Combining Distributed-Temperature Sensing With Inflow-Control Devices Provides Improved Injection Profile With Real-Time Measurement in Power-Water Injector Wells,” by Drew Hembling, and Garo Berberian, SPE, Saudi Aramco, and Mark Watson, Sam Simonian, and Garth Naldrett, SPE, Tendeka, pre- pared for the 2010 SPE Intelligent Energy Conference, Utrecht, The Netherlands, 23–25 March. The paper has not been peer reviewed. Combining Distributed-Temperature Sensing With Inflow-Control Devices for Improved Injection Profile EOR OPERATIONS For a limited time, the full-length paper is available free to SPE members at www.spe.org/jpt. JPT • JUNE 2010 79