Abstract The accurate detection and confirmation of formation pore pressure and fracture gradient has become almost essential to the drilling of deep wells with higher than normal pore pressure. Generally, the formation pressure is the presence of the fluids “oil, gas or salt water” in the pore spaces of the rock matrix. Therefore, the fluid confined in the pores of the formation rock occur under certain degree of pressure, generally called formation pore pressure. Formation pore pressure is defined as the pressure acting on the fluids in the pore space of the rock, which is equal to the difference between the total overburden stress and grain to grain stress. Normal formation pressure is equal to the hydrostatic head of the native formation fluid or water exerting from the top of water table to the subsurface formation depth. Hydrostatic pressure is the pressure in a column of salt water or usually defined as the pressure exerted by a column of fluid, the pressure is a function of the average fluid density and the vertical height or depth of the fluid column. In most cases, the fluid vary from fresh water with a density of (8.33 Ib/gal) (0.433 psi/ft) to salt water with a density of (9 Ib/gal) (0.465 psi/ft). Consequently the hydrostatic pressure gradient of such system will be greater in terms of (psi/ft) than that of a fresh water system and will be displayed on pressure depth plot by pressure gradient line whose slope is greater than that of fresh water hydrostatic pressure. Indeed, formation pore pressure depending on the magnitude of the pore pressure, it can be described as being either normal, abnormal or subnormal. Whereas defined as follows, we had defined normal pore pressure which is equal to the hydrostatic pressure, abnormal pore pressure is defined as any pore pressure that is greater than the hydrostatic pressure of the formation water occupying the pore space, and sometimes called overpressure or geopressure. Subnormal pore pressure is defined as any formation pressure that is less than the corresponding fluid hydrostatic pressure at a given depth. The objectives of this study are:To determine the origin, nature, causes and the location of the subnormal and overpressued formations in part of Sirte basin area. To determine a graphical correlation relating formation pore pressure and fracture gradients to depth for selected areas extending fromfurther east to North West in the basin.This study is determining the pore pressure and fracture gradient, for selected fields from eastern, central and western Sirte basin, using existing correlations which utilize log and drilling data measured for the selected wells in these areas. The casing setting depths as well as the maximum and the minimum mud weight gradients to be used for future drilling activities in these selected areas in Sirte basin have been determined. The location and the magnitude of the lost circulation zones as well as the overpressured zones have been determined and correlated with depth depending on the location of the studied area in the basin. It was found that the lost circulation zones are located at depths of approximately in the range 3000 to 6000 ft from east toward west. It is concluded that the calculated pore pressure and the fracture gradients values obtained from the log data are in good agreement with the values obtained form the drilling data. It is concluded that the results obtained in this study for the eastern part of Sirte basin was satisfactory and can be used with good confident for future drilling activities in the area, where the obtained results for either the central or the western parts of the basin are not enough to draw final conclusions for future mud design programs in these areas. It is therefore recommended that further investigation and extensive study should be conducted for these two areas by gathering enough log and drilling data from different fields in these area which was not available during this study.
احمد خليفة رمضان طنيش (2009)

Abstract The average recovery factor calculated for the whole reservoir is higher than the average recovery factor calculated from averaging the individual well recovery factor. The integrated recovery factor calculated from each well should be compared with recovery factor calculated for the reservoir as a whole using the material balance equation or the volumetric methods as a basis for the calculations. The difference between the two values is anindication of an inadequate well spacing for the reservoirIf (Np/N) each ≈ (Np/N)whole the distribution of the wells for the reservoir is adequate .If (Np/N) each < (Np/N)whole the distribution of the wells in the reservoir is inadequate .This indication of excess in number of wells .If (Np/N) each > (Np/N)whole the distribution of the wells in the reservoir is inadequate .This indication of the reservoir needs infill wells to be drilled.The number of infill wells depends on the relationship between recovery factor and number of wells. The infill wells location in the reservoir should be at high hydrocarbon pore volume and also it should be located in the trend of the easiest permeability path of oil movement.It was concluded that the number of wells existing in the Sharara field is not adequate therefore we recommend to increase the number of the wells as per the method enclosed in this study. The results of this study indicate that the calculated oil production decline rate constant is different from well to another which is an indication of variations of water influx into the reservoir.
مختار محمد غدير (2008)

Abstract Formation damage caused by inappropriate drilling, completion, work over and production schemes are a major cost to the oil and gas industry worldwide. Many potential pay zones have been misdiagnosed as nonproductive and payout on investment has often been delayed. The reservoir rock and resident fluids are essentially in a state of physicochemical and thermodynamic equilibrium. Disruptions in this equilibrium due to changes in pressure, temperature and fluid chemistry around the well bore region can create barriers to flow and yield lower production rates.Scale deposition is one of the most serious oil field problems primarily when two incompatible waters are involved .Two water types are called incompatible if they interact chemically and precipitate minerals when mixed .Typical examples are sea water, with high concentration of ,and formation water, with high concentration of ,and .Mixing of these types of water could cause CaSO4,BaSO4,and SrSO4 scales.In this research we analyzed pressure transient for different oil wells in Amal Field. The collected data as well as reservoir rock and fluids properties and well bore conditions and configuration was being inserted into MINITAB program to formulate mathematical model which can predict total skin in oil wells .We observed that model gives good results when we compared St calculated from build up test with St calculated from the model. A Mathematical Model was developed in this study which can be used by the production engineer in any sandstone reservoir in order to predict the possibility of damage forming in the well.The model can also be utilized to define the parameters causing the damage in the well from which adjustment can be made to reduce the chance of forming damage in the well bore.
عبد المحسن عاشور مقام (2008)