This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17458, “Interventionless Monobore Technology Used To Complete Challenging Offshore Horizontal Gas-Injection Wells Successfully,” by M.O. Etuhoko, SPE, P. Essel, and C. Terre, Total E&P–Elf Petroleum Nigeria, and L. Proctor, SPE, Halliburton Energy Services Inc., prepared for the 2005 Offshore Technology Conference, Houston, 2–5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission. Elf Petroleum Nigeria Ltd. is developing the Amenam/Kpono oil field on the Nigerian Continental Shelf in the eastern offshore Niger delta. The field development was extremely challenging, with high-reach departures of up to 2 miles. New technologies [e.g., reservoir drilling fluid, fluid-spring-operated valve, gravel-pack packer, tubing-tester flapper valve (TTFV), production packer, and permanent gauge] were integrated to satisfy all well needs, especially those of the challenging horizontal gas injectors. Introduction The first phase of the field development was for reservoirs R4, R9, R10, and R11 in the western and central parts of the field. Two drilling platforms, AMD1 and AMD2, were installed 345 ft apart and connected to a production platform (AMP1). The development involves drilling and completing 34 wells, of which 18 are oil producers, 5 are gas injectors, and 11 are water injectors. At the R4 reservoir level, gas injectors are required for pressure maintenance from initial production because the bubblepoint pressure is approximately equal to the reservoir pressure. A primary target in the developmental plan was to use enhanced completion equipment to reduce operational risks while completing as quickly as possible. A monobore-completion design with interventionless technology was chosen. All wells were to be developed with interventionless technology, which would allow running and pressure testing the completion string as often as necessary without deploying a slickline. It also would allow setting the production packer without a slickline. Well-Completion Design A detailed design used software to deter-mine the tubing stresses and fluid-temperature profiles. The packer/tubing link would be standard for all wells. The value of the thermal derating factor used was 0.05%/°C. Because of the well pressure and temperature conditions, a premium-joint tubing connection was used in the tubing-stress simulations. The calculations were run with 100% efficiency for tension strength and 80% efficiency for compression strength. The values were designated to meet the following criteria.