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Issaran fied Upper Dolomite Zone were subjected to a steam project by year 2006. The steam injection pressure is very important factor during the steam cyclic project as at any single injector difference in the performance of nearby wells may be attributed to (1) local differences in reservoir characteristics and initial fluid contents, (2) anisotropy in properties (perhaps a preferred fracture orientation), (3) effects of dip, (4) differences in well completion, operation, or impairment, and (5) differences in the location of fluid fronts in the reservoir. Normally the injection pressure measure during thermal operations to provide (1) information on the injectivity and productivity of wells and flow resistance in the reservoir, (2) confidence that equipment and wells are being operated at design pressure levels and within safe pressure limits, (3) information on the enthalpy of fluids, and (4) information about properties and conditions existing in the reservoir through the use of diagnostic well test and continuous pressure observations. The injection pressure play very important role on the oil production after the injection period. Here will discuss the pressure performance while steaming and its effect on the average oil production on the production period after. On Issaran Upper Dolomite fracture zone, 16 wells were subjected to two steam cycles and based on the injection performance these 16 wells were subdivide to three groups, the first group for the wells which showed a decline on the oil rate after the second cycle, second group for the wells showed sustain on the oil production after the second cycle and the third group showed an increase on the oil production after the second cycle. This paper will highlight these results, and the methodology taken for analyzing the data, and the ways of investigation taken to reach a certain conclusion by the injection pressure should not exceed the fracture pressure otherwise during the second cycle the average oil production will be decrease.

Laboratory studies show the existence of some strains of bacteria in field crude oils and formation waters. This work is concerned with studying the effect of the reservoir conditions such as temperature, salinity and lithology on the indigenous bacterial activities. Such study is an original contribution to the knowledge of microbial enhanced oil recovery (MEOR). Egyptian MEOR project at Cairo University succeeded to isolate a surfactant-producing microorganism "Pseudomonas Aeruginosa" from crude oil produced from an Egyptian oil field. Several displacement tests were conducted in sand pack model. A modified media was used to incubate and improve the growth rate, behavior and stimulation of Pseudomonas Aeruginosa. The results obtained from the current work showed that Pseudomonas Aeruginosa succeeded to increase the oil recovery by 20%. Pseudomonas Aeruginosa becomes able to resist the effect of temperature up to 70°C and salinity up to 150,000 ppm, when a specific incubation technique is applied. There is no significant effect on the behavior of the bacteria in the presence of the Dolomite and Kailinite inside the reservoir. The value of the oil recovery factor in case of incubation of the bacteria outside the model is greater than its value in case of incubation inside the model by about 5%. The results obtained are discussed and analyzed in terms of surface tension, hydrogen ion concentrations, viscosity, and conductivity of the effluent solutions.

Issaran was discovered on 1981 and the cumulative production up to 1998 was 0.7 MMbbls from 9 wells and the total reserve were 5 MMbbls from 500 MMbbls as original oil in place which result in a recovery factor less than 1% and reflect the big challenge to produce this field.The problem was that each reservoir has its own characteristic, which requires special approach to overcome its problems and optimize its production and reserves. As Zeit Formation contain massive sand, Upper and Lower dolomite due to its shallow depth the oil could not be produced as cold production, Gahrandal formation is consisted of three limestone bodies with permeability below 20 md and the last one is Nukhul zone which give some cold oil production due to its naturally heavy fracture. Theses difference characterization lead to apply different ways of reservoir management for each zone.The challenge of Scimitar is to produce these zones and reach to a production plateau in spite of the aging of the fields and its associated problems (low pressure, water cut increase, wells potential, sand production and corrosion, …. etc). Scimitar dedicated special multi disciplinary teams to propose and implement several strategies to achieve its goal and succeeded to have stable plateau around 6000 BOPD during year 2008.This paper will highlight the results of each zone and the achievement as the total wells drilled on the field up to now is 287 well and the total OOIP increases to 700 MMbbsl, the cumulative oil production on March 2009 is more than 10 MMbbls which gives more confidence about the successful of the new strategies for each zone. The steam project applied on the Lower and Upper Dolomite is consider the first successful cyclic steam project on the Middle East. The results of the producing wells in conjunction with the numerical 3D simulation study lead to prove that the recovery factor can be reach to 45% which gives total reserve around 300 MMbbls.

The Nukhul formation in the Gulf of Suez is highly fractured, depleted reservoir producing 9 to 10 API gravity heavy oil at water cuts up to 98%. Stimulation is required to enhance oil production and extend the life of the field. An inherent problem with these wells is poor acid placement during matrix acidizing, especially in reservoirs with high-permeability contrasts. Conventional acidizing results in the stimulation of water zones, and misses targeted oil zones. The high viscosity and low mobility of the Issran field heavy oil, in contrast with the strong mobility and low viscosity of the formation water, makes the problem even more pronounced.To temporarily plug the water zones and effectively stimulate oil zones with chemical diversion, a new surfactant-based chemistry has been introduced. When mixed in brine, it forms a high viscous gel. The gel maintains its viscosity when contacting water and breaks down when contacting oil, thus temporarily plugging the zones of high water saturation. When mixed in acid, the new system will stimulate and divert automatically based on in-situ gellation mechanism related to acid spending; thus achieving uniform distribution. In addition, the new acid system has a unique inherent property to limit acid penetration in high water saturation zones, while enhancing deeper penetration in high oil saturation layers.Conventional acid treatments have a low success rate in the Nukhul formation. More than 50% of the stimulated oil wells turned into 100% water producers. The new stimulation treatment fluids and placement techniques improved oil production and lowered WCs. Water cut before acid treatment ranged from 90% to 98%. After the treatment, water cuts lowered to the range from 40% to 75%, and post-oil production increased by as much as three- to eightfold.This study assesses the performance of the placement techniques and fluids used in the stimulation of the Nukhul formation based on field data. It also quantifies the economical added value resulting from the usage of the surfactant-based systems with respect to conventional matrix stimulation fluids.