H.H. Hanafy, SPE, Gulf of Suez Petroleum Company, S.M. Macary, Egyptian Petroleum Research Institute, Y.M. ElNady, SPE, Al Azhar University, A.A. Bayomi, SPE, Al Azhar University, and M.H. El Batanony, Egyptian Petroleum Research Institute Copyright 1997, Society of Petroleum Engineers, Inc. Abstract An accurate description of physical properties for crude oils is necessary for solving many of reservoir engineering and surface production operational problems. Ideally, crude oil properties are determined experimentally in the laboratory on actual fluid samples. However, in the absence of experimentally measured crude oil properties, one can resort to empirical PVT correlations. The purpose of this paper is to evaluate most of the empirically derived PVT correlations found in the literature during the last five decades by applying them to the Egyptian Crude Oils. The PVT measurements of 324 fluid samples covering a wide range of crude oils ranging from heavy to volatile oils have been used in this study. These samples were collected from 75 fields distributed along three different regions of Egypt including, the Gulf of Suez, Western Desert, and Sinai. In order to have a fair evaluation of the different correlations, special care was given to the limitations of data and nature of parameters used to derive these correlations. The results of this study were also compared with the results of similar studies performed on Egyptian oils as well as crude oils from other regions worldwide. Because the total separator gas-oil ratio is the key parameter to estimate the reservoir oil properties from most of the popular empirical correlations, this paper presents a new approach to correct the primary stage separator gas-oil ratio to estimate the total gas-oil ratio using the data base available for Egyptian oils. This paper concludes that due to regional ranges in crude oil compositions, a universal correlation that can be applied to different types of crude oils would be difficult to obtain. Therefore, correlations for a local region, where crude oil properties are expected to be uniform, would be a necessary alternative. Introduction The reservoir fluid data have many applications in different areas of the exploration and production process. While reservoir engineers generally have the greatest claim on such data, reservoir fluid analyses are also quite valuable to geologists and production specialists. One can resort to empirical PVT correlations to estimate the reservoir fluid data in the following cases:inability to obtain a representative sample,sample volume is insufficient to obtain a complete analysis,collected sample is nonrepresentative,quality check lab analysis,lab analyses are in error,estimating the potential reserves to be found in an exploration prospects,evaluating the original oil in place and reserve for a newly discovered area before obtaining the laboratory analysis to justify a primary development plan. This study evaluates the accuracy of the empirically derived PVT correlations relative to the experimental PVT for 324 Egyptian oil samples taken from 123 reservoirs in 75 fields. Table 1 presents the PVT data range for the available samples. The tested Correlations are used to estimate the bubblepoint pressure, oil formation volume factor, isothermal oil compressibility, oil density, and oil viscosity. Before measuring the accuracy of different correlations, it should be pointed out that the effective use of the correlations lies in an understanding of their development and knowledge of their limitations. Correlations Development and limitations Sutton and Farshad presented a detailed review about the development and limitations of the most widely used correlations. P. 733

H.H. Hanafy, SPE, Gulf of Suez Petroleum Company, S.M. Macary, Egyptian Petroleum Research Institute, Y.M. ElNady, SPE, Al Azhar University, A.A. Bayomi, SPE, Al Azhar University, and M.H. El Batanony, Egyptian Petroleum Research Institute Copyright 1997, Society of Petroleum Engineers, Inc. Abstract An accurate description of physical properties for crude oils is necessary for solving many of reservoir engineering and surface production operational problems. Ideally, crude oil properties are determined experimentally in the laboratory on actual fluid samples taken from the field under study. However, in the absence of experimentally measured crude oil properties, especially during the prospecting phase, or when only invalid samples are available, one can resort to empirically derived PVT correlations. During the last five decades, several correlations have been developed to estimate the crude oil properties. However, these correlations may be useful only in regional geological provinces and may not provide satisfactory results when applied to crude oils from other regions. The aim of this work is to derive and test new correlations to predict the fluid properties for Egyptian crudes including bubble point pressure, solution gas-oil-ratio, oil formation volume factor, oil compressibility, oil density, and oil viscosity. These correlations have been developed from the experimental PVT data of 324 fluid samples covering a wide range of crude oils ranging from heavy to volatile oils. The fluid samples have been taken from 176 wells located in 75 fields operated by 16 companies. This data represents 15 productive zones of 123 reservoirs distributed along three different regions of Egypt, including the Gulf of Suez, Western Desert, and Sinai. Sensitivity analysis indicated that the experimentally determined flash liberation gas-oil-ratio, which corresponds to the producing gas-oil-ratio, is the most correlative parameter with the bubble point pressure. Therefore the separator gas-oil ratio was used in this study as the key parameter for predicting the oil properties. The procedure for predicting the fluid properties using the new correlations is simple and straightforward. By starting with the separator gas-oil-ratio then going through good correlations between different pairs of fluid properties, one can obtain a complete set of PVT data for oil properties either at or above or below the bubble point pressure. Finally, this study compares the predicted properties from the new correlations and the commonly used empirical correlations by applying them to the experimental data base available for Egyptian crude oils. Introduction The reservoir fluid data have many applications in different areas of the Exploration and Production process. While reservoir engineers generally have the greatest claim on such data, reservoir fluid analyses are also quite valuable to geologists and production specialists. The process of collecting fluid samples may be repeated during different phases of a field since discovery till its mature phase.–A geologist may use correlations along with an oil or gas gravity measurement from a near-by well for help in obtaining an estimate of the potential reserves to be found in an exploration prospect.–After the exploration well is drilled and successful, a well test may allow those same correlations to be used with the known gravity, gas-oil ratio, and pressure data from the discovery well. In an ideal situation, a fluid sample may be recovered from the discovery well for analysis. P. 439

No abstract

This paper shows how Gupco (Gulf of Suez Petroleum Company) has successfully developed a heavy oil marginal reservoir by using high technologies such as reservoir simulation, 3-D visualization, coiled-tube dual completion, and coiled tube pipeline. The July 53 block was discovered in January 1986 with the drilling of the vertical platform proving well J-53. The well was drilled to test the Lower Rudeis formation in a 90-acre sliver block to the west of the main Lower Rudeis July field. The test indicated a potential of 1350 BOPD with an API gravity of 19 degrees, an oil viscosity of 7 CP, and a gas-oil-ratio of 85 SCF/STB. For this reservoir fluid type, the recovery factor was expected to be less than 5% under primary conditions. Therefore, the development of this fault block was put on hold until further studies could determine the optimum plan of depletion. Starting in 1993, GUPCO began studying small reservoirs such as the J53 block with a PC-based black oil simulator. In the case of J53, the simulator was used to match the short term DST from the discovery well, and then create multiple depletion scenarios. Waterflooding, it was discovered, would provide the best development plan. Use of the simulator provided insight into the recovery process, and reduced the development risk. Under primary recovery, the simulator confirmed a low ultimate recovery of 3% of the OOIP. With the optimal waterflooding plan, however, recovery could be improved to 23% of the OOIP. Considering that normal Lower Rudeis oil recovery approach 54% of the OOIP under waterflooding (in the main field with 32 degree API oil), the simulator provided a much more conservative estimate. The development of this fault block was started in May 1996 by drilling a high angle producer designed to be parallel and close to a major fault to encounter the full Lower Rudeis section. Waterflooding was started in December 1996 by completing an existing Nezzazat producer with a unique coiled-tube dual water injection - oil production completion. A 3 1/2 inch coiled tubing line was laid to provide injection water from a near platform at almost 7000 BWPD. Performance to date indicates a successful waterflood project. The well's production rate has increased from 1300 BOPD, before waterflood start, up to the peak production rate of 4100 BOPD.

More than thirty years ago, Gulf of Suez Petroleum company (Gupco) - Egypt, initiated the first waterflood project for El Morgan oil field. The company now operating 14 different waterflood reservoirs. These reservoirs have produced a cumulative oil representing 40% of their original oil-in-place. On average, the projected waterflood recovery factor is 54% of OOIP. Due to non-uniform lithology and non-uniform pattern of existing well locations in most reservoirs, peripheral waterflood was found to be the most suitable and economic waterflood pattern at project startup. Peripheral waterflooding has the advantage that it minimizes the number of injection wells by converting the watered-out producers. As these reservoirs become more mature, the line-drive pattern (peripheral + internal injection) was found to be more effective. Since most of the reservoirs are currently in the mature stage, good managing and close monitoring for each waterflood project is extremely important. This paper projects major strategies in managing the different waterflood projects to maximize both the oil production rate and oil recovery in optimum manners. This is being achieved through several common and familiar waterflood issues including in-fill drilling, zonal injection improvement, injection pattern modification, injection below formation parting pressure, pressure maintenance, workovers for production and injection wells, continuous data collection, and water quality monitoring. The paper also addresses the waterflood side effects such as scale buildup, reservoir souring and facilities corrosion. In addition, the paper discusses some of the innovative techniques that have been used to maximize waterflood recovery and enable waterflooding of marginal fields at a cost effective manner. Examples for these techniques are gas-cap water barrier injection, heavy oil waterflooding, coiled-tube water injection lines, slim-tube dual completions, and satellite waterflooding for pilot and marginal fields waterflooding. Introduction Waterflooding became an important part of most oilfield development strategies in the way to maximize the oil production revenue. A successful waterflood project can efficiently lead to maximize the overall sweep efficiency, which helps in increasing the oil recovery, and to maintain oil reservoir pressure above the fluid's bubble point pressure, which allow for more production rate levels. Several engineering studies were conducted late 1960's by the Gulf of Suez Petroleum Company (Gupco), Egypt, to evaluate the application of the first waterflood project. Strategies and economics of the waterflood project were primarily built based upon three items:projected incremental oil recovery of doubling the primary recovery factor,injection well pattern, utilizing the peripheral injection,water injection plant and injection lines, capacity and location. The company is currently operating 14 different waterflood reservoirs. total incremental secondary recovery has been estimated to be more than 1080 million barrels which is more than double the primary recovery as shown on Fig. 1. Historically, waterflooding in Egypt went through three different stages and during implementation process different strategies and economic models were set to fit the objective of each stage.