Gas lift has been applied successfully worldwide to increase well production. Artificial lift methods include pump assisted lift and gas lift. Gas lift is an artificial lift technique used to increase flow rate of oil wells. In this method, high pressure gas is injected into the well oil column to reduce its average density and make it flow to the surface. The main objectives of this study are to (1) investigate the effects of injection gas gravity, and reservoir temperature on the performance of gas lift, (2) develop a total-system production-optimization model using PROSPER and GAP simulation programs, and (3) increase oil production through optimization of gas injected/fluid-produced oil ratio in an Egyptian oil field utilizing the existing compression capacity. The developed production model has been used for production optimization and allocation of lift gas in a multi-well network, as well as for prediction of future system requirements and identification of any bottlenecking opportunities. The attained results indicated that (1) artificial lift using gas lift is a complex process including several variables, which have been considered for optimization, (2) the optimization of gas injection rate increased the attained oil production, (3) gas gravity of injected gas has an important effect on attained oil production while reservoir temperature has shown minimal effect on oil production, and (4) gas lift optimization in Egyptian field can help in overcoming the high pressure gas (HPG) constraints, saving gas for the nearby oil field and increasing the total production for both fields. The developed production model is completely implemented, field wide optimization is pursued and multi-well networked model is established. The application of the attained results is expected to have real impact in improving the gas lift performance in similar fields in the Middle-East and worldwide.
Sand production has always been a challenge for oil operators worldwide. Several parameters can lead to sand production, including poor cementing material in the reservoir, high production rates, and high drawdown applied to an unstable zone. The subject field consists of 105 wells; 90 of these wells are oil producing wells, 11 are water injection wells, two are dump flood wells, and two are water source wells. The primary challenge was to perform a gravel pack job on a high permeability water source well to deliver a planned rate of 25,000 bwpd. A study for the formation, the area, and the history of gravel packing in the operator fields was made to provide the optimum solution for the target well. The well was categorized as a critical well because of the various challenges and because of its importance to the operator in supplying the field with the injection water, which was down for months. The completion specifications, sizes, and the pumping techniques were agreed upon with the operator and the critical well review team. The well suffered from high losses resulting from the high permeability and long interval. The fluid losses had to be controlled before running in with the completion equipment and pumping the gravel pack treatment to avoid premature screenout. After perforating the pay zone, the well, as expected, suffered from high losses. These losses were controlled by pumping several non-damaging fluid loss pills until the losses were suitable for running the gravel pack assembly in the hole. The treatment was pumped in alternating stages of clean fluid and slurry fluid to aid in the displacement of the proppant in the annular space and to minimize the risk of bridging. Premium screens (6-5/8 in. with 175 micron filter) were used along with a 40/60 proppant. A 5-in. wash pipe was used to force the majority of the fluid in the slurry to remain in the casing/screen annulus to maximize sand transport, rather than leaking off through the screen and into the screen base pipe/wash pipe annulus. The treatment was successfully pumped, covering the 500 ft of screens and leaving excess volume of sand covering the blanks. The well was completed with an electrical submersible pump (ESP) and is producing 11,500 bwpd with no reported issues. The injection in the field is now online after being down for five months as a result of shutting down the well.
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