Kuwait Oil Company introduced new fluid practices to improve producibility in the Minagish oolitic limestone reservoir in Umm Gudair field. The approach was designed to minimise formation damage in the reservoir section and apply a more effective filter cake removal technique during the well completion. Experience on offset wells and results of return permeability studies showed that specially designed water-based drill-in fluids with optimally sized acid-soluble bridging particles were the preferred fluids for open hole completions on the Minagish reservoir. For removal of the cake and low permeability crush zone created by the drilling process a formic acid precursor (FAP) was used. The precursor is added to the completion fluid and reacts slowly with brine to release formic acid in the reservoir section. Conventional acidisation with HCl can cause wormholes, localised leak-off and failure to treat the entire interval effectively; FAP is in a neutral condition when placed. Localised reaction and loss zones are avoided and the released acid can act uniformly on the entire interval. Four wells in this area were sidetracked due to depletion in pressure and increasing water cut. All utilized the same drill-in fluid. Subsequently wells UG 116ST and UG126ST were stimulated with HCl, whereas UG 38STRE and UG 110ST were treated with the FAP. The two wells treated with the FAP had producibilities about twice those treated with HCl. The combination of well designed drill-in fluid and FAP has shown great promise of facilitating the drilling process and increasing the producibility of the well with significant economic benefit. This paper addresses practical applications of the drill-in fluid and the breaker and reports on several additional benefits that were obtained. Introduction The Umm Gudair field, situated in West Kuwait is managed by the Kuwait Oil Company (Gohain et al. 2007). The field is composed of two elongated dome like structures that are separated by a saddle shaped structure. The smaller westerly dome has a structural closure that trends north-south whereas the larger and broader dome in the east extends southwards. The field has been in production since 1962 when oil was discovered in the Minagish Formation. This formation is a massive peloidal-oolitic limestone reservoir with porosity in the range of 10 to 25 porosity units and average permeability about 100 mD but as high as 1000 mD at some intervals. The formation is depleted due to years of production and output is typically enhanced by pumps. Traditionally, the practice has been to drill this formation with a standard KCl/polymer fluid with sized calcium carbonate, since bottonhole temperture was about 180oF such a fluid was considered to be adequate. The reservoir section was left barefoot, stimulation with HCl was applied using a coil tubing unit and production was assisted by an electrical submersible pump connection. Commonly, production wells had horizontal drainholes with diameters of 6.125 or 4.75 inches and length of 1500 to 2000 ft. Generally speaking, drilling the reservoir section involved few issues but stimulation was more troublesome; problems included differential and mechanical sticking when running coiled tubing and subsequent increasing water cut. In 2006 it was decided to drill a new trial well (UG 132) in a hitherto undrained part of the field and to position it accurately within the formation in order to test new approaches to drilling techniques, the formulation of drilling fluid and filtercake clean up procedures. For example (Gohain et al. 2007), the horizontal drain was to be positioned approximately 450 m west of an abandoned well and a minimum of 65 ft above the oil/water contact. The drilling operation involved a "world first" utilisation of an advanced proprietary rotary steerable system together with logging while drilling (LWD) imaging technology. Optimisation of the drill-in fluid was based on typical core samples that had been collected earlier from an offset well and the new approach to the system for cleaning drilling damage avoided the use of hydrochloric or other live acid; instead a system was applied that was neutral when first spotted in the horizontal section but released acid in situ over a period of several hours.

Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application. Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems. This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data. In Future, this workflow will be part of full field Digital oil field implementation.

Continuous well performance monitoring plays a key role in making decision related to well workover and production optimization. Well parameters and corresponding rates over a period of time will represent the change in well performance. Live Well models are useful for estimating the continuous well production rates. Well models become live if they get updated with changing fluid and reservoir properties along with proper calibration to latest well conditions.In general industry practice is to update the model manually; this is a tidious and time consuming process. Umm Gudair Field Development team implemented a real time system using available resources that integrates and runs workflows between corporate data base, well surveillance data base and well models. Workflows were implemented as part of the real time system to calculate the well parameters from sensor readings and update the models to run on daily basis, such that the models become live and production rates will be estimated.The daily output generated from the workflows is basically updated well models and parameters along with production estimation report that will get emailed to users. The daily report contains the information about well status, potential, reasons for well closure etc. The workflows are intelligent enough to flag the need for model calibration and surface rate measurements. The daily estimated well parameters will be saved back to database for visualization. In conclusion, real time system was implemented to keep the well models live and useful as a tool for optimizing the oil production, improving the ESP's run life and delaying the well intervention requirements.