Operators are continuously striving to improve oil and gas field development strategies. One of the major improvements in field development strategies is enhancement of well completion designs that maximize profitability while maintaining high standards of reservoir management. Completion strategies have been transforming over the years from conventional wells to the recently drilled multilateral (ML) wells and smart wells that combine inflow control devices (ICDs) and electrical submersible pump (ESP) equipment. The new era of intelligent wells is focused on over-performing the old completion practices in terms of well productivity and reservoir sweep efficiency. Well-A was trial tested for the first time in an offshore field by deploying a hydraulic line wet mate (HLWM) connect system with the intelligent completion (IC). This tool allows de-completing the upper completion, which includes an encapsulated (pod) ESP portion, without the need to de-complete the lower intelligent completion. The completion operation of this well consists of two stages: the first stage consists of completing the well with the intelligent completion, HLWM connect tool and a production packer. The second stage is performed by pulling the production packer by disconnecting at the HLWM point and consequently running the ESP completion while maintaining the integrity of the lower intelligent well completion in place. The completion operation in Well-A was run in two stages only to trial test the reliability of the HLWM connect system in this field, since it was utilized for the first time. In subsequent wells, the intelligent completion can be run in one stage with the ESP integrated as part of the final completion design. A production optimization sequence utilizing a simulation model was used to analyze the potential of the well and selecting the right inflow control valve (ICV) settings from the two laterals for optimum reservoir drainage.
Over 70% of an onshore Saudi Arabian field maximum reservoir contact labeled wells are equipped with smart well completions; mainly to control undesirable effluent production. Several optimization best practices are routinely conducted through extensive sophisticated rate testing operations that are combined with the utilization of deployed intelligent devices. This entails the optimal setting of ICVs for ideal production and restriction of high gas or water laterals to determine their productivity indexes (PIs) and revive dead laterals. This paper documents the utilization of Netool in evaluating smart well contributions. A case study will be thoroughly discussed whereby a smart trilateral producer with flow meter log results exhibits unexpected flow contributions. Netool was used to evaluate the flow meter log to optimize the inflow control valve (ICV) settings. The model was validated with the actual flow rates of individual laterals. Moreover, Netool was utilized in evaluating and analyzing the current completion practices in terms of the spacing between the ICVs and the optimum blank pipe size.The results of the model contradict the flow meter log results. Several, rate tests were completed in the well resulting in more confidence in the model results. New proposed ICV settings balanced the flow rate and the pressure draw down between the three laterals. The paper will show that the greater the increase in the distance between the ICVs the greater the variance in the laterals contribution. The optimum spacing providing more balanced flow contribution came to be 300 ft. Sensitivity analysis was conducted over the blank pipe sizes, proving that a reduction of 40% pressure drop can be accomplished through having larger blank pipe between the ICVs from 3½" to 4½".
An evaluation process was conducted in assessing various solutions towards remedial action to a 7" liner with an identified leak in a water injector well. The leak to the 7" liner was identified through pressure testing of the well. A comprehensive investigation and analysis was performed to identify the liner condition, exact leak location and the extent of the leak. It was accomplished by analyzing all previous activities performed during the life of the well and through running special pressure testing as well as logging the well with ultrasonic and physical logs.The problem identification and proposed solutions were focused on curing the leak and bringing the well back on injection with the least operational risk and highest possibility of success. Corrosion and cement bond logs were ran and showed a better picture in regards to the extent of the corroded section and the quality of cement behind it. A caliber log was also run in the open hole which showed a washed out area near the 7" liner shoe.Several solutions that could repair the 7" liner leak were assessed including: i) cement squeeze in the leak zone, ii) setting an off bottom 4.5" liner and iii) using a 5.5" expandable liner. The evaluation process included each solution's impact on the future injectivity of the well, the effectiveness of each option, operational challenges and associated risks. Moreover, nodal analysis was performed to evaluate possible reduction of the injection rate associated with each solution.The final decision to repair the leak was to run an expandable liner and it was based on its advantages and deployment challenges. Lessons learned from this operation included the methods used to identify and assess the damage of the casing leak. Proper preparation and cleanout of the corroded section and the operation procedures performed to expand the liner are summarized in this paper.
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