No doubt that facies modelling process is a key process during building the static model which dominates all the petrophysical distribution after that. One of the best way to describe the facies change laterally across the reservoir is seismic attributes interpretation. However; unfortunately seismic attribute doesn't show accurate results in Western Desert in Egypt mostly because the reservoirs thickness is relative small. Several trials on seismic attributes were performed during performing a study on West Qarun field which is located in Abu El-Gharadig basin, Western Desert, Egypt but without reaching conclusive results. West Qarun wells are producing mainly from Middle Abu Rawash “G”, and Lower Abu Rawash “G” reservoirs which their thickness ranges from 30 to 60 ft. This paper presents another approach that was utilized to create facies log for each well integrating the petrophysical interpretation output and the core data as well. After that a thickness map for each facies per each reservoir was created. The resulted maps were utilized for facies model creation and consequently dominated the petrophysical properties distribution: porosity, permeability, and initial water saturation. Permeability-Porosity relationship was described as a function of flow zone indicator (FZI) considering the distributed facies model. Defining FZI range for each facies type yields to more accurate reservoir characterization and prevents usage of unreliable permeability multipliers during history match process. In spite of the absence of seismic attributes conclusive results, the resultant model showed excellent results during dynamic model in terms of production potential of different areas of the reservoir and the connectivity between different wells. The model showed good well by well match, total field match specially the ongoing pilot water injection project and also helped in planning the complete water injection project.

Background/Scope: Mechanical drilling, the gold standard to reach oil and gas reservoirs, is associated with drilling risks and increased time and costs. Laser drilling has emerged as a potential new drilling tool. However, studies about its practical applications are limited. This study investigates the feasibility and performance of laser technology in drilling oil wells. Methods: Core samples from the three lithologies were irradiated with Nd:YAG laser at different power intensities and exposure times while holding other parameters constant. Some core samples were saturated with brine to investigate the effect of fluid saturation. We developed a novel laser drilling system that enables users to input the lithology of encountered formations and output the power intensity needed to be drawn from the electric source to maintain the constant ROP. Results: The Nd:YAG laser beam fully penetrated the cores in all the study trials conducted in shale. In limestone, the laser beam fully penetrated the cores in 5/13 trials and partially penetrated them in 7 trials. The experiments could not be performed in sandstone due to rough surfaces and high porosity. The ROP values ranged between 58 and 66 ft/hr (mean 62.4 ±5.3 ft/hr) in shale and between 221.7 and 460.6 ft/hr (mean 328.5±71.5 ft/hr ft/hr) in limestone. The specific energy values ranged between 650 and 5433 KJ/cm 3 (mean 2885.1±1525.8 KJ/cm 3 ) for the limestone samples. A statistically significant inverse correlation was observed between laser energy and ROP (r=-0.952, P<0.001). The developed software was tested and validated. Added value: The study provides further evidence that laser drilling technology is a promising new technology for oil well drilling. The current study utilized high specific power laser which has not been previously used and developed a novel computer based constant ROP laser system. The rock removal mechanism should be shifted away from melting to spallation to achieve an efficient laser drilling mechanism through the optimization of the laser specific power and decreasing the specific energy during rock removal. Laser beam reflection, sample thickness and fluid saturation were identified as potential factors that influence the efficiency and performance of the laser drilling operation.

Mud loggers are the first (and sadly in some cases the only) people to look at the cuttings. To actually see what the rocks look like, feel like, occasionally even taste. Most people looking at a well will actually look at “wriggly lines” or at best the cuttings descriptions from the loggers or geologist, two or three lines of abbreviations “claystone, light grey to grey, soft to firm, occasionally hard, slightly calcareous, trace fine sand”. We have all read them, many of us have written them. These descriptions are incredibly useful and valuable, they are often all we have to understand the actual rocks and geology, especially with older wells. But in a world where we now enter the description and draw the logs with a computer, this information still comes from the subjective view of the logging geologist peering through a microscope In recent years, several tools have been developed to analyze drill cuttings from oil and gas wells. The most commonly used tools include X-ray fluorescence (XRF), X-ray diffraction (XRD), scanning electron microscopy (SEM) combined with energy dispersive X-ray spectroscopy (EDX), bulk density, and pyrolysis. Although each of these tools can be used to develop a limited determination of the in-situ rock character, the combination of three of these tools (XRF, SEM/EDX, and pyrolysis) can provide a more comprehensive picture of formation properties. The combination of XRF analysis with the SEM/EDX analysis is the key to the cuttings workflow. The exact location within the borehole can be determined and a robust mineralogy developed that is independent of normative mineralogy (typical XRF) or operator-interpretive mineralogy (XRD). Additional outputs include relative brittleness index, bulk density, lithology, fractional and textural relationships, total organic carbon (TOC) proxy, and a new porosity index. Trace and major elemental ratios are also available for precise stratigraphic placement. The addition of cuttings pyrolysis enables hydrocarbon typing, producible hydrocarbons, TOC, and total inorganic carbon (TIC) within each sample to be established. Chemical Lithostratigraphy uses whole rock inorganic geochemical (elemental) data, to give information on: Extrabasinal source area dominance and origin (volcanic, metamorphics, igneous, sedimentary), Extrabasinal component weathering or diagenesis (cementation) Intrabasinal components (Palaeo-environment and insitu origin of sediments) Chemical Lithostratigraphy analysis of cuttings can be done either in the laboratory or at the rig site using technology advanced Surface Logging Services (SLS) that includes both XRF and XRD equipment, in additions to SEM and Pyrolysis. Where an appropriate protocols uses for cuttings fraction that are most depth representative With the growing interest in hydraulically fracturing reservoirs both in main land USA and now globally, there has been a growing need to better characterize the reservoir to maximize hydrocarbon recovery while also reducing the overall cost in the recovery of the hydrocarbon. With current fracc-ing regimes relying on a large number of stages to ensure maximum recovery, which in many cases leads to upwards of 30% of these stages being unproductive. This reduces the overall profitability of the well even with maximum hydrocarbon recovery. With the ongoing development of automated mineralogy tools, such as the RoqSCAN, there is now the ability to characterize a reservoir at the well-site in real-time and also rapidly in a laboratory. In this paper we will review the current development of these mobile and ruggedized instruments using a real life project for Eagleridge Energy LLC, on their Burgess lateral well. The paper will show the application of automated mineralogical analysis of cuttings samples pre-drilling in defining stratigratic zones via mineralogy/elemental data. And then explore the application of the same data to assist, and in this case lead, the decision making process during directional drilling of the lateral well. The paper will also look at the use of the technology in defining tactical fracc-ing zone based on rock properties (e.g. ductility) determined from the mineralogical, elemental and textural data. This paper will show that through the use of automated mineralogical instruments, companies can pro-actively steer wells by identifying mineral changes within lateral borehole, indicating a deviation from the target zone. Additionally, this type of technology can be used to reactively steer by its ability to rapidly identification subsurface changes, such as unknown (undetected) faults. Finally the paper will show that through the better characterization of this reservoir companies can reduce the risk associated with the drilling of expensive lateral wells.

Formation drillability is one of the most important aspects for planning and designing a new oil/gas well since the factors affecting the drilling performance have complex relationships between formation properties, drill bit design and operational parameters. In view of high operating cost of drilling rigs, if Rate of Penetration (ROP) can be enhanced, it will reduce open-hole formation exposure time and complications associated with it resulting in significant savings in drilling time and cost can be realized Normally bit engineers utilize the assumed lithology from mud logs, detailed depth wise lithology of offset wells. The lithology can also be interpreted from conventional logging data such as Sonic, Gamma and Density. Furthermore, the rock's compressive strength is calculated using Compressional / Shear travel time (Sonic log), Bulk density (Density log) and Shale content (Gamma log). These utilized tools to detect the lithology and rock mechanical properties have an extent of uncertainty due to effects either related to borehole or drilling fluids that require extensive corrections. That degree of uncertainty subsequently can affect the drill bit design criteria, selection and viability of performance-enhancing features. This present paper reveals a new practical approach as a solution to minimize uncertainty in terms of bit design and selection by utilizing wellbore imaging and lithology & mineralogy wireline logs to precisely deliver an accurate input data to the drill bit design software modules.

Field development plan is an integration among Geophysical, Geological, Petrophysical and Reservoir Engineering data. The 3D seismic and wellbore data confirm that the field is composed of complex structures with variable of oil-water contact and differences in pressure surveys. A major source of these variations is compartmentalization, which is defined as limitation on the ability to produce hydrocarbons resulting from permeability barriers within a field. Two primary causes of compartmentalization. These are Stratigraphic and Structural variations in permeability. Ferdaus field is located in East Abu Gharadig basin in Western Desert, Egypt. It produces oil from Cretaceous sandstones mainly from three reservoirs: Middle, Lower Abu Roash “G” (A/R “G”) members and Upper Bahariya Formation. In Ferdaus field, Middle and Lower Abu Roash “G” members were deposited as barrier bars according to which the effects of the lateral and vertical sand facies changes within the productive sand intervals, have very limited impact on the pore connectivity based on Electric logs and mud log data. Therefore; the stratigraphic variations were neglected.. Structural compartmentalization, fault properties can constrain the fluid flow and pressure development, thus affecting decisions associated with the selection of the drainage strategy within reservoir management activities in order to maintain the pressure and increase the oil production rate. By using 3D seismic data, electric logs and pressure data made it possible to sudivide the field into compartments which differ in number based on the reservoir level. This gave good estimates for the Original Oil In Place (OOIP) and reserves which leads to apply a good development plan by infill wells and/or increasing the productivity by applying secondary recovery project (water injection).

Petroleum system modeling has mostly been the preserve of exploration departments in major oil companies, which have the specialist resources to execute these studies. However, as it is a dynamic tool for petroleum system analysis, it also has significant applications in the development stages. It may provide information on several different aspects of the areas surrounding a discovery: show which other closures were located on the same migration pathways from the same source and highlight the likely oil and gas distributions in these closures. show which satellite accumulations were effective traps and their hydrocarbon composition. The chance that the structure has been flushed with another hydrocarbon type, breached and re-charged, or only contains residual hydrocarbon may also be predicted. The compositional information from a 3D petroleum system model can be valuable in: Planning appraisal and satellite exploration drilling, Facilities planning where the hydrocarbon composition and the number of satellites that will contribute to the plateau are important to design vs. economic decisions, and Relinquishment decisions. A discovery well has encountered oil and there is a significant volume of the reservoir updip of the well. 3D petroleum system modeling can be used in determining the possibility of a gas cap and the necessity of the investment in an updip appraisal well. Furthermore with multiple compartments of which only one has been tested the understanding of the effectiveness of the fault seal is critical to determine if the closure may have different hydrocarbon compositions. The 3D petroleum system modeling can prioritize appraisal drilling to test structures that are most likely to have the desired fluid fill. Furthermore in the case of parts of the concession area has to be relinquished the 3D petroleum system modeling can be used to determine which areas has the lowest economical value in the development. The high-resolution charge, thermal and pressure histories are important boundary conditions which are required to understand the genesis of the field and the original properties of the oils, and then to obtain an improved understanding of the conditions under which the development hydrocarbons could have taken place (e.g.biodegradation, multi-phase hydrocarbon filling, thermal maturation, water washing, gravitational segregation, hydrocarbon migration along faults, etc). This provides the best possible definition of the charge, temperature and pressure histories, which will then be available to improve analyses of the genesis and distribution of Hydrocarbons.

The goal of the present work is to numerically simulate the effects of wellbore orientation on fracture initiation pressure (FIP). These simulations support the study of FIP sensitivity to arbitrary wellbore position and finding the orientations that correspond to the lowest FIP. A 3D numerical model of the fracture initiation from a perforated wellbore in linear elastic rock is used to model FIP. This model is based on the boundary element method (BEM) and maximum tensile stress (MTS) criterion. The data used were from different zones and blocks of a tight gas-bearing sandstone field in the Sultanate of Oman. The amount and quality of available data allowed comprehensive model development. The model is built for the four blocks of the main field, but can be applied to the other blocks and fields. Since the equations and correlations are not empirical and not field-specific, the model is applicable to a wide range of conditions. Some practical applications of the study include selection of the optimum perforated intervals intended for fracturing stimulation in deviated or almost horizontal wellbores where different parts of lateral sections are not exactly aligned with principal stresses. Drilling wells in a particular direction to the principal stresses for the specific reason to reduce the FIP has not been tested to date and is a subject to further discussion.

Dipmeter & image logging tools had gained wide acceptance in petroleum industry as a mean to define subsurface sedimentary structures and to detect geologic signatures of tectonic events. The advantage of dipmeter & image logging, over seismic is that they rely on their ability to provides accurate information's near the well bore and detect structural features beyond seismic resolution. Dipmeter & Imaging information in frontier areas with poor seismic imaging (scattered 2D seismic data over thrust & belt regime) is paramount from wildcat spud, mainly to initially correlate with surface geological data, later on constantly update the geological model and, of course, to visualize expected geological prognosis for the undrilled section. In the Kurdistan region (Iraq) usually the surface sections are drilled with air/foam air due to existing drilling risks. An operational imposed mud system that triggers several limitation from the data acquisition point of view. In this case the Joint Venture (Repsol Exploration as an Operator and Maersk as a partner) decided to use a High Definition Formation Micro Imager as a challenge against the lack of other wireline logging reliable tools (Sonic, etc…). Initially this High Definition Formation Micro Imager with its high vertical resolution of 0.2”, was designed electronically for greater reliability and clearer images in extreme conditions, could provide an excellent image in Air/Foam mud. This tool data revealed that the dip patterns over the intervals suffer from increasing and decreasing of dips downward with repeated azimuth directions (generally from NE to SW). These changes were not accompanied by any fracture displacement (faulting). These zones were interpreted due to the presence of series of recumbent and overturned folding, where the direction of dip decreases till the axial plane of the structure, then increasing again towards the opposite flank with different azimuth direction. This interpretation helped matching the updated geological model (unexpected recumbent & overturned folding) with the surface geology, and determined a startup (geological prognosis) for the undrilled section. This paper documents that a High Definition Formation Micro Imager can be successfully acquired in such tough Air/Foam mud conditions. It also provided reliable downhole information for surface section project decision. This data proved to be very important to update the geological model and provide a required geological prognosis.

Nile Delta Basin is a mature gas producer in Egypt, from the early sixties till present many gas discoveries were made in both on & offshore areas in the Pliocene and Miocene reservoirs. The first gas field, Abu Madi Field, was discovered onshore Nile Delta in 1967, by AGIP (IEOC) with the drilling of the Abu Madi-1 (AM-1) well. The Abu Madi field started to be developed since 1970, it's producing wells increased to 21 and by end-1992, the field had a capacity of 400 MCF/d; being that time the biggest gas field in Egypt. Subsequently of the gas-bearing reservoir discovered in Abu Madi Formation (Late Messinian) - becomes one of the main targets in on and offshore area of Nile Delta. The stratigraphic framework of the Abu Madi Fm., was reveal through years, now a days this formation is considerate as a sedimentary infilling of a fluvial paleovalley characterized by stacked fluvial-deltaic sandstone and shale's. The classical Abu Madi Fm., lithostratigraphic layering comes from the Abu Madi/El Qaraa fields where the reservoirs sandstones levels have been named, starting from bottom, as follows: Level 3 (Lower, Main, Upper and 3A), Lev2 and Lev 1. The recently wells targeting the Lev 3 Main and Lev 3A reservoirs did not achieved the estimated remaining recoverable resources. In this study the new 3D seismic data, production history and petrophysical data were integrated in order to relocate the unachieved residual OGIP and also to find new drilling opportunities for additional potential resources.

Murzuq Basin is an intractratonic sag basin located in the southwestern part of Libya and considered as one of the major profitable basins in North Africa. The basin has been developed during the Late Precambrian-Early Paleozoic time, which went through various reactivated tectonic events. These events were dominant during the Paleozoic era coincided with regional unconformities and major sea level changes that resulted in complex geological configuration of both structural and stratigraphic. Detailed subsurface analysis implemented utilizing seismic and well log dataset of the concession NC186 to evaluate the main Paleozoic tecto-stratigraphic complexities within the northern part of the basin. This analysis guided to understand the major Paleozoic polyphase tectonic evolution in the area of study. Steep reverse basement faults, folds, positive flower structures and paleohighs and paleolows of glacial topography are evidently indication of the observed large-scale tectonic Paleozoic elements. From this study, the basement faults are anticipated to be genetically related to the Pan African Orogeny in origin and played major controller of all Paleozoic events. These faults are striking NW-SE with a vertical throw up to 300 meters and an oblique fault plane. Late Ordovician glacial valleys encountered in the area with more than seven kilometers of wide, which have eroded more than 500 meters of Middle Ordovician and Cambrian deposits. The incised valleys took place along the strike of the major basement faults in the area. The entire large-scale analyzed elements interpreted to be generated, directly and indirectly, by different tectonic regimes (i.e. compressional, extensional, strike-slip and combination) exclusively during Paleozoic time. Therefore, from the detailed interpretation; six phases are introduced as the main representative tectonic episodes of in the northern part of Murzuq Basin. These tectonic phases and episodes have controlled the petroleum system in the basin and the area of study in particular.

Real-time azimuthal acoustic measurements were introduced recently in the logging-while-drilling (LWD) industry. For the first time, this technology was used as part of the bottomhole assembly (BHA) to acquire information related to principal stress orientations in the deltaic to marine Zubair clastic sequence of onshore Kuwait. A deviated 8.5-in. hole section of the well was planned through sand-shale sublayers with a borehole inclination ranging from 46 to 88°. This section is characterized by time sensitive borehole deterioration and significant variations in pore pressure. These factors result in severe hole instability and ultimately stuck pipe events and require relatively high mud weights to maintain wellbore stability. LWD azimuthal acoustic technology, free from chemical sources, was used for the first time both in drilling and wipe modes to facilitate time-lapse field stress and wellbore stability analysis. Principal stress orientations were identified from three different sources, including borehole breakouts from azimuthal acoustic caliper, density image, and acoustic anisotropy evaluation. The results were then compared with the existing offset well data and an existing geomechanical 3D model. Variations in observed stress orientation, seismic reflection pattern, and pressure history in offset wells were used to map a fault that is responsible for bypassed oil and for the occurrence of tar and gas. The interpretation was extended to other low throw strike-slip faults; additional fault compartments were identified that could affect the pressure maintenance scheme of the field. This paper discusses the planning, design, and use of LWD azimuthal acoustic technology in this case history well. It also describes the viability, integrity, and reliability of the interpreted results and their use in a detailed geological interpretation in terms of stress orientation, fault trapping, and areal fluid variation. The optimization of real-time drilling operations and petrophysical data acquisition requirements are also investigated to improve future field development and overall reservoir management strategies.

The recent achievement in unconventional reservoirs has established the objective of reevaluating the oil-bearing tight carbonates as potential oil production reservoirs. Of these carbonates, the Turonian Abu Roash D (AR/D) tight limestone in the Abu Sennan field of the Western Desert, Egypt contains oil, but has extremely poor recovery. The challenge in this study is to define the effective parameters that control the various petrophysical attributes of this tight reservoir and their influence on reservoir recovery. Integrated sedimentological analysis and poroperm characterization was performed based on various data sets, including conventional core analysis, mercury injection tests, and petrographic inspection. A core-calibrated image-perm software algorithm was processed to evaluate the heterogeneity of reservoir pore system and to provide a continuous and azimuthal output of high resolution porosity and permeability. The AR/D limestone succession (approximately 82 m thick) consists almost entirely of offshore-outer ramp bioclastic wackestone-mudstone facies, with the exception of a reduced reservoir-forming interval (approximately 10 m thick), which consists of inner- to mid-ramp facies. The outer-ramp offshore facies have very poor reservoir quality, with total porosity of less than 9% and permeability values that never exceed 0.1 mD. The reservoir-forming interval begins with storm beds of whole fossil rudstone and bioclastic wackestone, and gradationally terminates upward with inner-ramp shoal beds (5 m thick) of benthic foraminiferal peloidal packstone. The shoal facies measure a noticeably enhanced porosity (15 to 27%) with a relative increase in permeability (up to 2.3 mD). However, a petrographic inspection with resistivity image analysis showed a clear paucity of visible mega- and meso-pores or significant natural open fractures. This means that the reservoir pore system is of the intercrystalline microporosity type, which is confirmed by scanning electron microscope (SEM) and the measured pore throat radii ranging between 1 and 0.005μ. The prevalence of microporosity in the best zone of AR/D reservoir is also evident by a unimodal porosity range distribution shown by an image-perm output. This homogeneous and volumetrically significant microporosity nature may provide a favorable recovery if a suitable fracturing design is applied. This study highlights the effect of microporosity types on the permeability of tight limestone reservoir, and emphasizes the workflow and benefits of the image-perm technique in evaluating the poroperm system and heterogeneity in the porosity distribution in carbonate reservoirs.

Multisource and multiscale modelling of formation permeability is a crucial step in overall reservoir characterization. Thus it is important to find out an efficient algorithm to accurately model permeability given well logs data. In this paper, an integrated procedure was adopted for modelling formation core permeability given well logs and Lithofacies classification for a well in sandstone formation in South Rumaila Oil Field, located in Iraq. The core permeability was modelled give well logs interpretation: neutron porosity, shale volume, and water saturation as function of depth, in addition to the vertical Lithofacies sequences. The statistical learning algorithms that were adopted in this paper are Generalized Linear Models (GLM) & Smooth Generalized Additive Model (sGAM) for permeability and Probabilistic Neural Networks (PNN) for Lithofacies prediction. Firstly, the Probabilistic Neural Networks was adopted for modelling and prediction the continuous and discrete Lithofacies distribution. The classified Lithofacies were considered as a discrete independent variable in core permeability modelling in order to provide different model fits given each Lithofacies type to capture the permeability variation. Then, GLM and sGAM models were applied to build the statistical modelling and create the relationship between core permeability and the explanatory variables of well logs and Lithofacies. GLM considers the maximum likelihood function to estimate the coefficients; however, sGAM considers a sum of nonparametric smoothing functions to identify nonlinear relationships depending on the degree of smoothing. The cubic spline function provides the closest fit as it minimizes a penalized negative log-likelihood function, which represents the smooth terms, by minimizing of an internal generalized cross validation function by iteratively reweighted least squares. In sGAM results, Root Mean Square Prediction Error (RMSPE) and the R-squared have better values than GLM especially in the reduced models. The stepwise elimination was considered to find the best predictors subset in GLM; nevertheless, the non-influential predictors in sGAM were recognized and treated as splines smoothed term to ensure rejection for the null hypothesis and ensure the confidence interval to be greater than 95%. The sGAM model has led to overcome the multicollinearity that was available between one pair of the predictors by using the smoothed terms. All the multivariate statistics analyses of Lithofacies classification and permeability modelling with results visualizations were done through R, the most powerful open-source statistical computing languages.

The Western Desert accounts for approximately two thirds of Egypt's surface area. The region can be divided into a number of large scale structural provinces which developed along lines of weakness in the African basement, in response to lateral movements between Europe and Africa. Seismic evidence has revealed a subsurface comprising a series of low relief horsts and grabens. In places however, the structural history is more complex. The Yusif field located near the Qatara depression, is habituated and, therefore has poor seimic data. Three wells were drilled in the field, Yusif -1X, Yusif-3, and Yusif-4 respectively. The fourth well is planned for the most promising area between the three wells. Formation microimaging was performed in the three wells, and interpretation of the images helped to delineate the sand body propagation and geometry in the field and choose the most promising area for drilling the fourth well. The Lower Abu Roash “G” member usually appears as a fining upward profile from conventional openhole logs. Facies analysis was performed on the “G” member with manual sedimentary dip picking, which revealed the internal structures and directions that can't be observed from conventional logs. Correlation with existing openhole logs showed continuity in the vertical and lateral distribution of the sand body, and queries about the relation between the sand bodies in the three wells arose. The relationship between sand bodies can't be solved by conventional openhole logs correlation. Paleocurrent analysis was performed for the sand bodies in the three wells. The results showed that the main trend of the channel belt propagation is NE. Yusif-3 and Yusif-4 wells were drilled within the channel belt while Yusif-1X location was at the channel margin. Correlation is based on electrofacies, which was extracted from high-resolution formation microimaging in the three wells. It was found that the “G” member top is changed based on high-resolution electrofacies detection, and the fourth well was placed closer to Yusif-3 and Yusif-4 based on the recommendations on the channel activity propagation as identified in the formation microimaging. The sand body thickness in the fourth well was almost double the thickness that was found in the previous three wells.

Late Jurassic Mrabtine formation, limited at the bottom by Tlalett formation and overlain by Early Cretaceous silicoclastics, is both reservoir and seal. It is a proven oil bearing complex sandstone reservoir, in southern Gulf of Gabes, onshore Tunisia. The seal consists in the upper evaporitic Member of Mrabtine formation. Detailed core study provided better knowledge of its heterogeneous lithology and petrophysical properties, in order to identify the different rock types and evaluate the reservoir potential. In Jeffara Basin, the gross reservoir thickness can reach more than 300 m. Detailed sedimentological and petrophysical study of more than 40 meters of core, consisting in core logging, microfacies analysis, SEM analysis and routine core analysis (He-porosity, horizontal air-permeability and grain density) were undertaken to determine the different facies types and their relative petrophysical properties. In fact, the sampling was made considering the changes in the lithology. Both sedimentological and petrophysical analyses were used to define the different rock types characterizing Mrabtine reservoir. The study revealed complex lithology and mineralogy of Mrabtine formation. The sandstone levels are, indeed, intercalated by several thin (millimetric to centimetric) and relatively thick carbonate layers (up to 60 cm). At the base of the reservoir, the carbonates thickness may extend to 7 m. Furthermore, there are frequent silty and shaly layers intercalated within the reservoir. Eight facies types may be distinguished: 1) sandstones with small scale cross-stratifications, 2) bioturbated sandstones, 3) silty sandstones, 4) bioturbated dolomites, 5) dolomitic limestones, 6) bioclastic limestones and/or dolomites, 7) siltstones and shales and 8) Evaporites. The sandstones are mostly fine quartzitic, with common occurrence of clay minerals (kaolinite, dickite and illite) and some iron sulfides and carbonates (pyrite, ankerite and siderite). The facies associations correspond to shallowing upward cycles, going from shaly, carbonate and silty deposits, to mostly fine sandy wave- and tidal-dominated shallow marine sediments, capped by evaporitic chicken-wire anhydrites. The routine core analysis confirmed the heterogeneity of the reservoir due to its complex lithology and mineralogy. The sandstones present the best reservoir potential (up to 25 % porosity and up to 425 mD permeability) and the best poroperms are recorded within cross-stratified sandstones. The fine low poro-perm carbonate, silty and shaly layers constitute flow barriers which should be considered in geological reservoir modeling. The complex lithology of the Mrabtine formation should also be taken into account in case of scale prevention studies to avoid injecting fluids which are incompatible with the variable matrix nature of Mrabtine reservoir.

Histrorically, Upper Safa is considered to be the source rock of the gas and condensate accumulated in Lower Safa stratum in Obaiyed Field. Both of Upper and Lower Safa units are parts of Khatatba formation “Jurassic age, Western Desert coulumn, Egypt”. The integration of all petrophysical and geochemical data indicated that, there is a rich organic Carbon embedded in the formation with a high britteleness ratio. As a result of the opportunity identification, there is an operational scope being studied now to proceed with a haydrulic fracturing stimulation targeting the sweet intervals “Intervals of high TOC and high Britteleness ratio” aiming to maximize the whole gas and condensate production of the field. This paper is summarizing the opportunity identification process and results using available petrophysical and geochemical data. Six wells had been used in this study where there is a complete set of well and continuous petrophysical data exist in all of them supported by geochemical analysis reports. Specific interpretation techniques were utilized to identify the opportunity from the logs. The property of Total Organic Carbon was estimated from logs using standered DeltaLogR Passey Technique and then verified using measured data. The rock briteleness property was estimated from avilable acoustic sonic logs “Compressional and Shear slowness”. The type of Kerogen and level of Maturity were recognized from geochemical sources. The data integration provided a well identification of the shale gas opportunity. As a part of complete assessment study of unconventional resources, a dedicated subsurface team was formed in order to evaluate the connectivity of Upper Safa, estimate the in place volumes and define the development options. The team also proposed on short term scale performing a vertical hydraulic fracturing in one of the sweet wells in order to prove the evaluation concept and increase total field production. The success of this project is measured by three aspects: first, proving the presence of commercial shale gas plays in Upper Safa unit, second, maximizing the gas and condensate production from the field and finally, on the long term scale, unlocking commercial unconventional gas resource for future generations in Western Desert, Egypt.

West Dikirnis field is located in the Nile delta of Egypt. It contains a thin oil rim with a thick gas cap and strong water aquifer. It is considered the second oil discovery in the Nile delta after El Tamad Field (Operated by Petroceltic & El Mansoura Pet Co). The development of this thin oil rim is very challenging due to: 1) complexity of the fluid system (volatile oil, retrograde condensate gas cap gas), 2) complexity of the geology of the field (compartmentalization, fracturing, and rapid lithological variation), 3) high heterogeneity in reservoir properties (permeability ranges from 200 mD to 11 D), and 4) strong water drive. This paper represents a case history of developing WD field. It presents a complete development plan of this thin oil rim and its rich gas cap and how to maximize liquid (oil & condensate and LPG) recovery through different stages by optimizing drilling/completion strategy, reservoir management, and production processing. The production strategy of this field was put into phases. In the first phase, the thin oil rim reservoir was developed through vertical and deviated wells for the purpose of collecting geological and reservoir engineering data required for full field development. In this phase the simulation studies showed positive effects of recycling the produced gas into the reservoir gas cap for the purpose of maintaining the reservoir pressure and decreasing the liquid losses due to the expected retrograde condensation in the gas cap gas. This first phase has shown strong, but variable, aquifer effects on the production wells. It also showed a great deal of lithological variations within very short distances in the field. In the second phase, and to overcome the geological and aquifer heterogeneities, it was decided to develop the field with horizontal wells completed with ICD's (Inflow Control Devices). This type of development helped achieve the following: (i) overcome the geological complexity, and (ii) to keep the well away from the water table, (iii) control the water rise by gas cap gas recycling, and iv) normalize the water moving front towards the well bore by the use of ICD's. The studies have shown that the above strategy increases the oil recovery factor by about 50%. In the third phase an LPG & Refrigeration project was constructed in order to maximize the liquid production from this field. Currently, an EOR project is put in focus for further increasing of the liquid recovery from this field partly through vaporizing the remaining oil.

The study area covers Temsah concession in the eastern sub-basin, offshore Nile Delta, Egypt. Despite the Serravallian play within this area is proven, observations made on recently acquired seismic data suggest its potentiality might be significantly larger than initially evaluated. Over 25 wells have been drilled within Temsah Development Lease since late 70's targeting turbiditic channelized flow deposits fitting a part of the four way dip closure Akhen-Temsah anticline. The interval of study shows a general fining upwards GR log pattern with a sub-parallel thinning up-dip seismic reflectivity. Amplitude map analysis through this interval shows southwest-northeast anomaly trends, shifting upwards to the southeast and becoming thinner and narrower. New hydrocarbon potential arises under the assumption that reservoir rock distribution is restricted to the anomaly trends mapped on the over-laying levels, from those producing from the main field area, and located down-dip on the southeastern flank of the structure. The associated risk derives from the reservoir architecture and possible lateral up-dip communication to underlying beds through permeable beds.

Lower Reineche hydrocarbon-bearing limestones is subdivided into four different layers the first three ones (LRN1, LRN2, LRN3) belong to nummulite-rich unit and represent the main reservoir however the fourth layer (LRLs), which corresponds to an argillaceous limestones, is not considered as reservoir layer although its fair porosities. The sedimentological study based on CL description, USB, TS, and SEM analyses allowed the identification of eight facies. In the cored wells, the specified facies coupled to the FMI interpretation are used in order to recognize the specific response of each facies. Then the comparison of the FMI logs of the non-cored wells with those of the cored ones assists the prediction regarding facies and reservoir characteristics and helps to fill interpretive gaps when comprehensive formation evaluation data is not available. The CMR Logs show generally one modal T2 distribution illustrating the existence of only one fluid type except the LRN2 showing bimodal T2 distribution. In addition, this T2 signal is wide expressing a large pore size distribution (micro- to macroporosities). The sedimentological study proved the existence of matrix microporosity, an intergranular porosity between Nummulite tests and an intragranular porosity within Nummulites which is effective only when affected by microfractures (meso- to macroporosities). For Lower Reineche limestones, integration of sedimentological, RCA, FMI and CMR studies specified the different facies in addition to the porosity and permeability distribution in the reservoir. Nummulit biofabric and early diagenesis are the main factors that control the petrophysical characteristics of the Nummulit bearing limestones. The understanding of the heterogeneity and the distribution of the porosity and the permeability in this area is important for the reservoir modeling and the hydrocarbon (gas mainly) saturation.

The Sweetspot Quality Index (SSQI) is a single index that represents the quality of a shale sweetspot. Four indices are used to calculate the SSQI: the Reservoir Quality Index (RQI), Completion Quality Index (CQI), Conventional Behavior Index (CBI), and Operation Index (OI). The RQI is calculated from porosities (rock porosity, organic porosity, and natural fractures), saturation, TOC, Ro, and reservoir pressure, and the CQI is calculated from shale brittleness, and the existence of micro fractures and laminations. The CBI is calculated from porosity, permeability, saturations, reservoir pressure, viscosity, and residual oil, and the OI is estimated from hydrocarbon market price, source rock depth, and cost of operations. These four indices include all the approaches that compare and evaluate shale plays and together offer a more complete view of grading and scaling shale sweetspots. The proposed technique has been applied to different data sets from North American shale plays, and the final results are very consistent with best practices. Due to this consistency, this approach has the potential to become a standard evaluation technique for E&P and service companies.