No abstract

El-Morgan Field was discovered in 1965 and is located offshore in the Gulf of Suez (GoS) approximately 160 miles south of Suez, Egypt. Peak Production was approximately 300,000 BOPD within only three years. El- Morgan is considered one of the giant fields since its STOOIP is estimated to be approximately 2.689 billion BO with an ultimate recoverable reserve around 1.439 billion BO. Over its history, more than 250 wells were drilled. Currently, 179 wells are operating (125 producers & 54 Injectors). El-Morgan is considered highly sophisticated field due to reservoir heterogeneity (Kareem reservoir), moderate stratification, limited aquifer support, high bubble-point pressure, low-permeability layers and its friable sand. Due to the high bubble-point pressure and high initial-rate (Pi=2,990psi & PB=2,269psi), the bubble-point pressure was encountered early in the field resulted in using peripheral injection to support reservoir pressure. In addition the reservoir heterogeneity while injecting peripherally, it is believed that significant oil reserves were being bypassed and were potentially unrecoverable. This paper presents an integrated approach to optimize the development for a complex field from both subsurface and operations views. It also shows studies conducted to maximize the asset value, explains how the development strategy have been revised over time, to augment oil ended by using an EOR method nowadays (BrightWaterTM). All of these studies are coupled to the economical calculations. Managing giant fields with a significant potential is very important since each incremental 1% in RF will increase the ultimate recovery by tens of millions oil barrels. Also through this paper you will assure importance of certain reservoir evaluation tools and how you can optimize them to increase ultimate recovery factor. Paper is an excellent example for reservoir management that resulted in more than 52% primary RF.

October field is a large oil field located in North Gulf of Suez (N-GoS) of Egypt. The reservoir was discovered in the mid-1980s. More than 20 wells have been drilled in the reservoir, revealing considerable complexity and heterogeneity. Until late 1999, the production mechanism was natural depletion above bubble point. At that time water injection was started and has since been extended to all the field.Based on pressure performance data, the reservoir could be divided into five relatively independent producing areas. In initial field development, material balance techniques were used to evaluate group "5" performance. Using graphical techniques, a dynamic STOIIP close to the mapped STOIIP was obtained. However, due to reservoir heterogeneity, material balance techniques were not adequate for providing reliable predictions under water injection.A reservoir model that could accurately predict future production had to include reservoir heterogeneity. Within an integrated subsurface team environment, a geological static model was constructed and a numerical reservoir simulation study was performed.This model led the team to conclude that this area was affected by water injection wells in the adjacent block and that the current reservoir pressure could be about 400 psi higher than previously expected. As a result, an immediate static survey was run that confirmed the simulation results. A recommendation was made to return previously shut-in wells to production resulting in an oil gain of 1,500 BOPD.

This work presents new Modified Black Oil (MBO) PVT properties (Rs, Rv, Bo, and Bg) correlations for volatile oil and gas condensate reservoir fluids. These new correlations do not require the use of fluid samples or EOS calculations. The correlations have the advantage of taking into consideration the effect of surface separator configuration (two and three stages) and conditions (separators pressures and temperatures).The correlations were developed using fourteen actual reservoir fluid samples (7 gas condensates, 3 near critical fluids, and 4 volatile oils) spanning a wide range of fluid behavior and characteristics. Whitson and Torp method was used to generate Modified Black Oil (MBO) PVT properties that were used as a data set for correlations development.The MBO PVT properties data points were generated by extracting the PVT properties of each sample using commercial PVT software program at twelve different separator conditions spanning a wide range of surface separator configuration and conditions to generate twelve curves for each sample. A statistical approach using a statistical software program (SPSS) was used to develop the new correlations models.The results of the new models show reasonable agreement between Modified Black Oil PVT properties generated from the new correlations and the MBO properties extracted using Whitson and Torp method. The average absolute error in the correlations was 8.5% for volatile oils and 17.5% for gas condensates.These correlations were also validated by comparing the results of modified black oil simulation using MBO PVT properties generated from these correlations to the results of full equation of state (EOS) compositional simulation. Also, the generalized material balance equation (GMBE) was used to calculate the initial oil/gas in place (IOIP/GIIP) for many simulated cases using PVT data generated from the new correlations and data generated from EOS models. The advantage of the new correlations comes from being the first in the industry (to the best of our knowledge) that explicitly take into consideration the effects of surface separators configurations (two or three stages) and conditions. Also, all input parameters in the correlations are readily available from field production data. These correlations do not require elaborate calculation procedures or PVT reports.