The demand for digital oil field solutions in artificially lifted wells is higher than ever, especially for wells producing heavy oil with high sand content and gas. A real-time supervisory control and data acquisition solution has been applied in a large-scale thermal pilot for 28 instrumented sucker rod pumping wells in North Kuwait. This paper focuses on the advantages of real-time data acquisition for identifying production-optimization candidates, improving pump performance, and minimizing down time when using intelligent alarms and an analysis engine. Real-time surveillance provided a huge amount of information to be analyzed and discussed by well surveillance and field development teams to determine required actions based on individual well performance. Controller alarms and intelligent configurable alarms in one screen enabled early detection of unexpected/unwanted well behavior, re-investigating well potential, and taking necessary actions. The challenge was to handle heavy oil, sand, and gas production, maintain all wells at optimum running conditions before and after steam injections, and take into consideration the effect that injections would have on nearby wells. Recording in the database a "tracking item" for each well event enabled review and evaluation of the wells and creation of optimization reports. The daily, 24-hour surveillance of the wells resulted in observing common problems/issues on almost all wells and other individual issues for specific wells. The following are examples of problems identified in early stages: Detected wells with gas interference before they reached gas lockDetected wells with high flowline pressure before flowline blockage resulted from sand productionDetected wells with standing valve and/or traveling valve leak—resulting from sand production—before the pump stuck The availability of such a supervisory control and data acquisition (SCADA) system helped in guiding the operations team to further investigate only specific items from the field side to confirm the findings. The ability to remotely control the wells and remotely change configuration of the variable speed drive parameters enabled instant implementation and continuous production optimization. The powerful SCADA solution enabled creating short- and long-term plans and monitoring the behavior of wells while the implementation phase was executed. For the first time in South Ratqa in North Kuwait, the smart field approach was implemented in a thermal pilot using sucker rod pumps; and the results will be used as a reference for the upcoming projects in this area. Real-time monitoring and data storage in a single database with an analysis engine provided fully automated surveillance and the capability of remotely controlling and applying required actions for production optimization.

The robust construction, ease of operation and maintenance of Sucker Rod Pump (SRP) is a stand-alone artificial lift method owning mostly to its simplicity. SRP are widely used positive displacement pump in land and offshore oilfield applications for lifting of heavy, medium or light oil with gas and water. In this paper, one such implementation of SRP is discussed which are simulated for rigless installation with insert anchor in existing failed artificial lift system. The failure of existing artificial lift system such as PCP, ESP or even SRP itself. Causes loss of cumulative production of the asset and thus economic disadvantage. The scheduling of rig to carry replacement based on oil priority further effects this interval which are generally overlooked. In this paper, implementation of SRP in such existing failed artificial lift system is discussed, carried rigless using insert anchor pump. Thus continuation of maintenance of asset production even after failure of artificial lift system. Such rigless installation opens window preferably of installations carried in wells with lower than expected productivity index. Which may have caused the existing system failure due to operation not being in the pumping range. In this paper, firstly simulation is carried as per the well test of recent failed artificial lift system for maximum production rate with maximum plunger size of the existing tubing size for insert anchor and flowing bottom hole pressure (FBHP). Secondly, rigless installation with economic advantage in comparison to installation with rig is discussed. Thirdly, the successful completion of installing SRP in 3 ½" tubing rigless is discussed with various existing failed artificial lift system. The paper evaluates for design and installation of artificial lift method of SRP through rigless flush-by unit with schematics in failed existing artificial lift system. Generally, with passage of time the formation productivity index drops due to various reasons. Thus the added advantage of resetting the pump at any depth along the production tubing, assists further in the location for minimum free gas percentage and hence extended run life, based on actual well test data and fluid level survey. The comparative results between the existing and new installation remain as a database for advantage in scheduling of rigless installation for optimum production. The design results are extensively discussed with schematics for effective rod stress, torque, rod and surface unit loading for a range of production rate.

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